PNM RESOURCES INC (Form: 10-Q, Received: 10/30/2015 17:35:38)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015



Commission File	Name of Registrants, State of Incorporation,	I.R.S. Employer
Number	Address and Telephone Number	Identification No.
001-32462	PNM Resources, Inc.	85-0468296
	(A New Mexico Corporation)
	414 Silver Ave. SW
	Albuquerque, New Mexico 87102-3289
	(505) 241-2700

001-06986	Public Service Company of New Mexico	85-0019030
	(A New Mexico Corporation)
	414 Silver Ave. SW
	Albuquerque, New Mexico 87102-3289
	(505) 241-2700

002-97230	Texas-New Mexico Power Company	75-0204070
	(A Texas Corporation)
	577 N. Garden Ridge Blvd.
	Lewisville, Texas 75067
	(972) 420-4189

Indicate by check mark whether each registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.



PNM Resources, Inc. (“PNMR”)	YES	ü	NO
Public Service Company of New Mexico (“PNM”)	YES	ü	NO
Texas-New Mexico Power Company (“TNMP”)	YES		NO	ü

(NOTE: As a voluntary filer, not subject to the filing requirements, TNMP filed all reports under Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.)

Indicate by check mark whether each registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).



PNMR	YES	ü	NO
PNM	YES	ü	NO
TNMP	YES	ü	NO

Table of Contents

Indicate by check mark whether registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act).

Large accelerated

filer

Accelerated

filer

Non-accelerated

filer

Smaller Reporting Company

PNMR

PNM

TNMP

Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES NO ü

As of October 23, 2015 , 79,653,624 shares of common stock, no par value per share, of PNMR were outstanding.

The total number of shares of common stock of PNM outstanding as of October 23, 2015 was 39,117,799 all held by PNMR (and none held by non-affiliates).

The total number of shares of common stock of TNMP outstanding as of October 23, 2015 was 6,358 all held indirectly by PNMR (and none held by non-affiliates).

PNM AND TNMP MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS (H) (1) (a) AND (b) OF FORM 10-Q AND ARE THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTION (H) (2).

This combined Form 10-Q is separately filed by PNMR, PNM, and TNMP. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants. When this Form 10-Q is incorporated by reference into any filing with the SEC made by PNMR, PNM, or TNMP, as a registrant, the portions of this Form 10-Q that relate to each other registrant are not incorporated by reference therein.

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

INDEX



	Page No.
GLOSSARY	4
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS (UNAUDITED)
PNM RESOURCES, INC. AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	7
Condensed Consolidated Statements of Comprehensive Income	8
Condensed Consolidated Statements of Cash Flows	9
Condensed Consolidated Balance Sheets	11
Condensed Consolidated Statement of Changes in Equity	13
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	14
Condensed Consolidated Statements of Comprehensive Income	15
Condensed Consolidated Statements of Cash Flows	16
Condensed Consolidated Balance Sheets	18
Condensed Consolidated Statement of Changes in Equity	20
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	21
Condensed Consolidated Statements of Comprehensive Income	22
Condensed Consolidated Statements of Cash Flows	23
Condensed Consolidated Balance Sheets	24
Condensed Consolidated Statement of Changes in Common Stockholder's Equity	26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	79
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	110
ITEM 4. CONTROLS AND PROCEDURES	113
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	113
ITEM 1A. RISK FACTORS	114
ITEM 6. EXHIBITS	114
SIGNATURE	116

Table of Contents

GLOSSARY



Definitions:
ABCWUA		Albuquerque-Bernalillo County Water Utility Authority
Afton		Afton Generating Station
AFUDC		Allowance for Funds Used During Construction
ALJ		Administrative Law Judge
AMS		Advanced Meter System
AOCI		Accumulated Other Comprehensive Income
APS		Arizona Public Service Company, the operator and a co-owner of PVNGS and Four Corners
ASU		Accounting Standards Update
BACT		Best Available Control Technology
BART		Best Available Retrofit Technology
BDT		Balanced Draft Technology
BHP		BHP Billiton, Ltd, the parent of SJCC
Board		Board of Directors of PNMR
BTU		British Thermal Unit
CAA		Clean Air Act
CCB		Coal Combustion Byproducts
CCN		Certificate of Convenience and Necessity
CO ₂		Carbon Dioxide
COFA		Capacity Option and Funding Agreement
CSA		Coal Supply Agreement
CTC		Competition Transition Charge
D.C. Circuit		United States Court of Appeals for the District of Columbia Circuit
Delta		Delta-Person Generating Station, now known as Rio Bravo
DOE		United States Department of Energy
DOI		United States Department of Interior
EGU		Electric Generating Unit
EIB		New Mexico Environmental Improvement Board
EIP		Eastern Interconnection Project
EIS		Environmental Impact Statement
EPA		United States Environmental Protection Agency
EPE		El Paso Electric
ERCOT		Electric Reliability Council of Texas
ESA		Endangered Species Act
Exchange Act		Securities Exchange Act of 1934
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIP		Federal Implementation Plan
Four Corners		Four Corners Power Plant
FPPAC		Fuel and Purchased Power Adjustment Clause
FTY		Future Test Year
GAAP		Generally Accepted Accounting Principles in the United States of America
Gallup		City of Gallup, New Mexico
GHG		Greenhouse Gas Emissions
GWh		Gigawatt hours
IBEW		International Brotherhood of Electrical Workers
IRP		Integrated Resource Plan
IRS		Internal Revenue Service

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ISFSI		Independent Spent Fuel Storage Installation
KW		Kilowatt
KWh		Kilowatt Hour
LIBOR		London Interbank Offered Rate
Lightning Dock Geothermal		Lightning Dock geothermal power facility, also known as the Dale Burgett Geothermal Plant
Lordsburg		Lordsburg Generating Station
Luna		Luna Energy Facility
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MMBTU		Million BTUs
Moody’s		Moody’s Investor Services, Inc.
MW		Megawatt
MWh		Megawatt Hour
NAAQS		National Ambient Air Quality Standards
Navajo Acts		Navajo Nation Air Pollution Prevention and Control Act, Navajo Nation Safe Drinking Water Act, and Navajo Nation Pesticide Act
NDT		Nuclear Decommissioning Trusts for PVNGS
NEC		Navopache Electric Cooperative, Inc.
NEE		New Energy Economy
NEPA		National Environmental Policy Act
NERC		North American Electric Reliability Corporation
New Mexico Wind		New Mexico Wind Energy Center
NMAG		New Mexico Attorney General
NMED		New Mexico Environment Department
NMIEC		New Mexico Industrial Energy Consumers Inc.
NMPRC		New Mexico Public Regulation Commission
NMSC		New Mexico Supreme Court
NOx		Nitrogen Oxides
NOPR		Notice of Proposed Rulemaking
NRC		United States Nuclear Regulatory Commission
NSPS		New Source Performance Standards
NSR		New Source Review
OCI		Other Comprehensive Income
OPEB		Other Post Employment Benefits
OSM		United States Office of Surface Mining Reclamation and Enforcement
PCRBs		Pollution Control Revenue Bonds
PNM		Public Service Company of New Mexico and Subsidiaries
PNM 2013 Term Loan Agreement		PNM’s $75.0 Million Unsecured Term Loan
PNM 2014 Term Loan Agreement		PNM’s $175.0 Million Unsecured Term Loan
PNM Multi-draw Term Loan		PNM’s $125.0 Million Unsecured Multi-draw Term Loan Facility
PNM New Mexico Credit Facility		PNM’s $50.0 Million Unsecured Revolving Credit Facility
PNM Revolving Credit Facility		PNM’s $400.0 Million Unsecured Revolving Credit Facility
PNMR		PNM Resources, Inc. and Subsidiaries
PNMR 2015 Term Loan Agreement		PNMR’s $150.0 Million Unsecured Term Loan
PNMR Development		PNMR Development and Management Company, an unregulated wholly-owned subsidiary of PNMR

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PNMR Revolving Credit Facility		PNMR’s $300.0 Million Unsecured Revolving Credit Facility
PNMR Term Loan Agreement		PNMR’s $100.0 Million Unsecured Term Loan
PPA		Power Purchase Agreement
PSA		Power Sales Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas
PV		Photovoltaic
PVNGS		Palo Verde Nuclear Generating Station
RA		San Juan Project Restructuring Agreement
RCRA		Resource Conservation and Recovery Act
RCT		Reasonable Cost Threshold
REA		New Mexico’s Renewable Energy Act of 2004
REC		Renewable Energy Certificates
Red Mesa Wind		Red Mesa Wind Energy Center
REP		Retail Electricity Provider
Rio Bravo		Rio Bravo Generating Station, formerly known as Delta
RMC		Risk Management Committee
ROE		Return on Equity
RPS		Renewable Energy Portfolio Standard
RSIP		Revised State Implementation Plan
S&P		Standard and Poor’s Ratings Services
SCE		Southern California Edison Company
SCPPA		Southern California Public Power Authority
SCR		Selective Catalytic Reduction
SEC		United States Securities and Exchange Commission
SIP		State Implementation Plan
SJCC		San Juan Coal Company
SJGS		San Juan Generating Station
SJPPA		San Juan Project Participation Agreement
SNCR		Selective Non-Catalytic Reduction
SO ₂		Sulfur Dioxide
SPS		Southwestern Public Service Company
TECA		Texas Electric Choice Act
Tenth Circuit		United States Court of Appeals for the Tenth Circuit
TNMP		Texas-New Mexico Power Company and Subsidiaries
TNMP 2011 Term Loan Agreement		TNMP’s $50.0 Million Secured Term Loan
TNMP Revolving Credit Facility		TNMP’s $75.0 Million Secured Revolving Credit Facility
TNP		TNP Enterprises, Inc. and Subsidiaries
Tucson		Tucson Electric Power Company
UG-CSA		Underground Coal Sales Agreement
Valencia		Valencia Energy Facility
VaR		Value at Risk
WACC		Weighted Average Cost of Capital
WEG		WildEarth Guardians

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands, except per share amounts)
Electric Operating Revenues	$	417,433		$	413,951		$	1,103,187		$	1,089,008
Operating Expenses:
Cost of energy	124,255			132,499			353,939			354,532
Administrative and general	46,375			42,190			130,161			131,283
Energy production costs	42,168			43,287			129,627			136,422
Regulatory disallowances	—			—			1,744			—
Depreciation and amortization	47,503			44,295			139,013			128,424
Transmission and distribution costs	16,768			16,884			50,123			49,857
Taxes other than income taxes	18,859			17,997			55,093			51,641
Total operating expenses	295,928			297,152			859,700			852,159
Operating income	121,505			116,799			243,487			236,849
Other Income and Deductions:
Interest income	1,151			2,084			4,842			6,241
Gains on available-for-sale securities	2,536			962			12,116			8,234
Other income	6,165			2,895			16,844			7,648
Other (deductions)	(3,222		)	(2,084		)	(10,591		)	(7,185		)
Net other income and deductions	6,630			3,857			23,211			14,938
Interest Charges	27,528			30,115			86,714			89,621
Earnings before Income Taxes	100,607			90,541			179,984			162,166
Income Taxes	35,752			31,055			61,621			53,368
Net Earnings	64,855			59,486			118,363			108,798
(Earnings) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Net Earnings Attributable to PNMR	$	61,045		$	55,653		$	107,058		$	97,262
Net Earnings Attributable to PNMR per Common Share:
Basic	$	0.77		$	0.70		$	1.34		$	1.22
Diluted	$	0.76		$	0.69		$	1.34		$	1.21
Dividends Declared per Common Share	$	0.200		$	0.185		$	0.600		$	0.555

The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Net Earnings	$	64,855		$	59,486		$	118,363		$	108,798
Other Comprehensive Income (Loss):
Unrealized Gain on Available-for-Sale Securities :
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $1,200, $(137), $(1,213) and $(3,946)	(1,862		)	210			1,882			6,256
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $3,925, $1,059, $8,838 and $4,547	(6,090		)	(1,628		)	(13,714		)	(6,997		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(583), $(508), $(1,749) and $(1,524)	905			780			2,715			2,340
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $276, $0, $276 and $53	(428		)	—			(428		)	(100		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $3, $0 and $(58)	—			(6		)	—			109
Total Other Comprehensive Income (Loss)	(7,475		)	(644		)	(9,545		)	1,608
Comprehensive Income	57,380			58,842			108,818			110,406
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Preferred Stock Dividend Requirements of Subsidiary	(132		)	(132		)	(396		)	(396		)
Comprehensive Income Attributable to PNMR	$	53,570		$	55,009		$	97,513		$	98,870

The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	118,363		$	108,798
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	165,563			157,687
Deferred income tax expense	62,511			55,553
Net unrealized (gains) losses on commodity derivatives	1,251			(67		)
Realized (gains) on available-for-sale securities	(12,116		)	(8,234		)
Stock based compensation expense	3,748			4,680
Regulatory disallowances	1,744			—
Other, net	(4,301		)	(642		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(23,783		)	(22,158		)
Materials, supplies, and fuel stock	(3,629		)	5,494
Other current assets	37,756			(19,816		)
Other assets	12,350			30,502
Accounts payable	1,275			79
Accrued interest and taxes	28,233			32,488
Other current liabilities	(12,731		)	(21,197		)
Other liabilities	(40,662		)	3,074
Net cash flows from operating activities	335,572			326,241

Cash Flows From Investing Activities:
Additions to utility and non-utility plant	(411,606		)	(293,361		)
Proceeds from sales of available-for-sale securities	166,097			82,222
Purchases of available-for-sale securities	(166,268		)	(81,644		)
Return of principal on PVNGS lessor notes	21,694			20,758
Purchase of Rio Bravo	—			(36,235		)
Other, net	2,891			(3,433		)
Net cash flows from investing activities	(387,192		)	(311,693		)

The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	(3,000		)	(49,200		)
Long-term borrowings	463,605			255,000
Repayment of long-term debt	(333,066		)	(125,000		)
Proceeds from stock option exercise	7,394			5,495
Awards of common stock	(18,955		)	(15,573		)
Dividends paid	(48,188		)	(44,600		)
Valencia’s transactions with its owner	(12,107		)	(12,749		)
Other, net	(5,402		)	(2,030		)
Net cash flows from financing activities	50,281			11,343

Change in Cash and Cash Equivalents	(1,339		)	25,891
Cash and Cash Equivalents at Beginning of Period	28,274			2,533
Cash and Cash Equivalents at End of Period	$	26,935		$	28,424

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	63,046		$	60,075
Income taxes paid (refunded), net	$	(1,636	)	$	(2,529	)

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(8,748	)	$	(6,674	)

The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	26,935	$	28,274
Accounts receivable, net of allowance for uncollectible accounts of $1,363 and $1,466	110,562		87,038
Unbilled revenues	61,739		63,719
Other receivables	22,234		39,857
Materials, supplies, and fuel stock	67,256		63,628
Regulatory assets	4,957		47,855
Commodity derivative instruments	6,144		11,232
Income taxes receivable	5,614		6,360
Current portion of accumulated deferred income taxes	26,383		26,383
Other current assets	76,161		58,471
Total current assets	407,985		432,817
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	242,795		250,145
Other investments	490		1,762
Non-utility property	3,404		3,406
Total other property and investments	246,689		264,851
Utility Plant:
Plant in service and plant held for future use	6,147,782		5,941,581
Less accumulated depreciation and amortization	2,043,482		1,939,760
	4,104,300		4,001,821
Construction work in progress	366,980		190,389
Nuclear fuel, net of accumulated amortization of $51,719 and $44,507	79,954		77,796
Net utility plant	4,551,234		4,270,006
Deferred Charges and Other Assets:
Regulatory assets	464,766		491,007
Goodwill	278,297		278,297
Commodity derivative instruments	3,369		—
Other deferred charges	100,512		92,347
Total deferred charges and other assets	846,944		861,651
	$	6,052,852	$	5,829,325

The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015			December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	102,600		$	105,600
Current installments of long-term debt	125,000			333,066
Accounts payable	120,052			110,029
Customer deposits	12,502			12,555
Accrued interest and taxes	81,932			53,863
Regulatory liabilities	2,205			1,703
Commodity derivative instruments	984			1,209
Dividends declared	16,063			16,063
Other current liabilities	57,249			70,194
Total current liabilities	518,587			704,282
Long-term Debt	1,980,381			1,642,024
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	949,642			891,111
Regulatory liabilities	472,035			466,143
Asset retirement obligations	111,595			104,170
Accrued pension liability and postretirement benefit cost	66,346			110,738
Commodity derivative instruments	—			477
Other deferred credits	107,072			103,759
Total deferred credits and other liabilities	1,706,690			1,676,398
Total liabilities	4,205,658			4,022,704
Commitments and Contingencies (See Note 11)
Cumulative Preferred Stock of Subsidiary
without mandatory redemption requirements ($100 stated value; 10,000,000 shares authorized; issued and outstanding 115,293 shares)	11,529			11,529
Equity:
PNMR common stockholders’ equity:
Common stock outstanding (no par value; 120,000,000 shares authorized; issued and outstanding 79,653,624 shares)	1,165,895			1,173,845
Accumulated other comprehensive income (loss), net of income taxes	(71,300		)	(61,755		)
Retained earnings	668,722			609,456
Total PNMR common stockholders’ equity	1,763,317			1,721,546
Non-controlling interest in Valencia	72,348			73,546
Total equity	1,835,665			1,795,092
	$	6,052,852		$	5,829,325

The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.

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PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



	Attributable to PNMR												Non- controlling Interest in Valencia
	Common Stock			AOCI			Retained Earnings			Total PNMR Common Stockholder’s Equity			Non- controlling Interest in Valencia			Total Equity
	(In thousands)
Balance at December 31, 2014	$	1,173,845		$	(61,755	)	$	609,456		$	1,721,546		$	73,546		$	1,795,092
Proceeds from stock option exercise	7,394			—			—			7,394			—			7,394
Awards of common stock	(18,955		)	—			—			(18,955		)	—			(18,955		)
Excess tax (shortfall) from stock-based payment arrangements	(137		)	—			—			(137		)	—			(137		)
Stock based compensation expense	3,748			—			—			3,748			—			3,748
Valencia’s transactions with its owner	—			—			—			—			(12,107		)	(12,107		)
Net earnings before subsidiary preferred stock dividends	—			—			107,454			107,454			10,909			118,363
Subsidiary preferred stock dividends	—			—			(396		)	(396		)	—			(396		)
Total other comprehensive income (loss)	—			(9,545		)	—			(9,545		)	—			(9,545		)
Dividends declared on common stock	—			—			(47,792		)	(47,792		)	—			(47,792		)
Balance at September 30, 2015	$	1,165,895		$	(71,300	)	$	668,722		$	1,763,317		$	72,348		$	1,835,665

The accompanying notes, as they relate to PNMR, are an integral part of these financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Electric Operating Revenues	$	333,437		$	334,993		$	870,826		$	873,434
Operating Expenses:
Cost of energy	105,708			115,097			299,302			304,365
Administrative and general	41,927			37,519			118,450			116,731
Energy production costs	42,168			43,287			129,627			136,422
Regulatory disallowances	—			—			1,744			—
Depreciation and amortization	29,042			27,524			86,446			81,629
Transmission and distribution costs	10,478			10,693			31,519			32,202
Taxes other than income taxes	10,404			10,258			31,194			30,359
Total operating expenses	239,727			244,378			698,282			701,708
Operating income	93,710			90,615			172,544			171,726
Other Income and Deductions:
Interest income	1,152			2,102			4,869			6,295
Gains on available-for-sale securities	2,536			962			12,116			8,234
Other income	5,369			1,804			13,661			5,359
Other (deductions)	(2,616		)	(1,197		)	(7,230		)	(4,844		)
Net other income and deductions	6,441			3,671			23,416			15,044
Interest Charges	19,837			20,092			59,477			59,927
Earnings before Income Taxes	80,314			74,194			136,483			126,843
Income Taxes	27,258			25,142			44,560			42,331
Net Earnings	53,056			49,052			91,923			84,512
(Earnings) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Net Earnings Attributable to PNM	49,378			45,351			81,014			73,372
Preferred Stock Dividends Requirements	(132		)	(132		)	(396		)	(396		)
Net Earnings Available for PNM Common Stock	$	49,246		$	45,219		$	80,618		$	72,976

The accompanying notes, as they relate to PNM, are an integral part of these financial statements.

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Net Earnings	$	53,056		$	49,052		$	91,923		$	84,512
Other Comprehensive Income (Loss):
Unrealized Gain on Available-for-Sale Securities :
Unrealized holding gains (losses) arising during the period, net of income tax (expense) benefit of $1,200, $(137), $(1,213) and $(3,946)	(1,862		)	210			1,882			6,256
Reclassification adjustment for (gains) included in net earnings, net of income tax expense of $3,925, $1,059, $8,838 and $4,547	(6,090		)	(1,628		)	(13,714		)	(6,997		)
Pension Liability Adjustment:
Reclassification adjustment for amortization of experience (gain) loss recognized as net periodic benefit cost, net of income tax expense (benefit) of $(583), $(508), $(1,749) and $(1,524)	905			780			2,715			2,340
Total Other Comprehensive Income (Loss)	(7,047		)	(638		)	(9,117		)	1,599
Comprehensive Income	46,009			48,414			82,806			86,111
Comprehensive (Income) Attributable to Valencia Non-controlling Interest	(3,678		)	(3,701		)	(10,909		)	(11,140		)
Comprehensive Income Attributable to PNM	$	42,331		$	44,713		$	71,897		$	74,971

The accompanying notes, as they relate to PNM, are an integral part of these financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	91,923		$	84,512
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	111,371			108,069
Deferred income tax expense	46,268			45,313
Net unrealized (gains) losses on commodity derivatives	1,251			(67		)
Realized (gains) on available-for-sale securities	(12,116		)	(8,234		)
Regulatory disallowances	1,744			—
Other, net	(5,288		)	(355		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(16,220		)	(16,782		)
Materials, supplies, and fuel stock	(3,328		)	5,697
Other current assets	36,707			(20,806		)
Other assets	12,126			29,796
Accounts payable	(794		)	10,100
Accrued interest and taxes	22,856			19,984
Other current liabilities	(12,099		)	(21,586		)
Other liabilities	(34,224		)	2,841
Net cash flows from operating activities	240,177			238,482

Cash Flows From Investing Activities:
Utility plant additions	(301,410		)	(199,771		)
Proceeds from sales of available-for-sale securities	166,097			82,222
Purchases of available-for-sale securities	(166,268		)	(81,644		)
Return of principal on PVNGS lessor notes	21,694			20,758
Purchase of Rio Bravo	—			(36,235		)
Other, net	3,051			(3,404		)
Net cash flows from investing activities	(276,836		)	(218,074		)

The accompanying notes, as they relate to PNM, are an integral part of these financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net	—			(49,200		)
Short-term borrowings (repayments), affiliate, net	—			(26,000		)
Long-term borrowings	313,605			175,000
Repayment of long-term debt	(214,300		)	(75,000		)
Valencia’s transactions with its owner	(12,107		)	(12,749		)
Dividends paid	(46,548		)	(30,659		)
Other, net	(4,934		)	(1,196		)
Net cash flows from financing activities	35,716			(19,804		)

Change in Cash and Cash Equivalents	(943		)	604
Cash and Cash Equivalents at Beginning of Period	25,480			21
Cash and Cash Equivalents at End of Period	$	24,537		$	625

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	42,680		$	41,606
Income taxes paid (refunded), net	$	(1,450	)	$	(215	)

Supplemental schedule of noncash investing activities:
Changes in accrued plant additions	$	(9,933	)	$	(10,586	)

The accompanying notes, as they relate to PNM, are an integral part of these financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	24,537	$	25,480
Accounts receivable, net of allowance for uncollectible accounts of $1,363 and $1,466	83,401		67,622
Unbilled revenues	52,342		54,140
Other receivables	19,036		37,622
Affiliate receivables	8,859		8,853
Materials, supplies, and fuel stock	64,186		60,859
Regulatory assets	3,064		43,980
Commodity derivative instruments	6,144		11,232
Income taxes receivable	6,363		6,105
Current portion of accumulated deferred income taxes	12,418		12,418
Other current assets	70,796		53,095
Total current assets	351,146		381,406
Other Property and Investments:
Investment in PVNGS lessor notes	—		9,538
Available-for-sale securities	242,795		250,145
Other investments	252		397
Non-utility property	96		96
Total other property and investments	243,143		260,176
Utility Plant:
Plant in service and plant held for future use	4,728,597		4,581,066
Less accumulated depreciation and amortization	1,556,065		1,486,406
	3,172,532		3,094,660
Construction work in progress	307,676		169,673
Nuclear fuel, net of accumulated amortization of $51,719 and $44,507	79,954		77,796
Net utility plant	3,560,162		3,342,129
Deferred Charges and Other Assets:
Regulatory assets	337,712		357,045
Goodwill	51,632		51,632
Commodity derivative instruments	3,369		—
Other deferred charges	90,389		81,264
Total deferred charges and other assets	483,102		489,941
	$	4,637,553	$	4,473,652

The accompanying notes, as they relate to PNM, are an integral part of these financial statements.

Table of Contents

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015			December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Current installments of long-term debt	$	125,000		$	214,300
Accounts payable	95,194			86,055
Affiliate payables	17,070			18,232
Customer deposits	12,502			12,555
Accrued interest and taxes	52,994			29,298
Regulatory liabilities	2,205			1,703
Commodity derivative instruments	984			1,209
Dividends declared	132			132
Other current liabilities	40,798			52,053
Total current liabilities	346,879			415,537
Long-term Debt	1,464,991			1,276,357
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	758,182			715,814
Regulatory liabilities	435,473			425,481
Asset retirement obligations	110,545			103,182
Accrued pension liability and postretirement benefit cost	59,367			102,850
Commodity derivative instruments	—			477
Other deferred credits	90,034			86,023
Total deferred credits and liabilities	1,453,601			1,433,827
Total liabilities	3,265,471			3,125,721
Commitments and Contingencies (See Note 11)
Cumulative Preferred Stock
without mandatory redemption requirements ($100 stated value; 10,000,000 authorized; issued and outstanding 115,293 shares)	11,529			11,529
Equity:
PNM common stockholder’s equity:
Common stock outstanding (no par value; 40,000,000 shares authorized; issued and outstanding 39,117,799 shares)	1,061,776			1,061,776
Accumulated other comprehensive income (loss), net of income taxes	(70,872		)	(61,755		)
Retained earnings	297,301			262,835
Total PNM common stockholder’s equity	1,288,205			1,262,856
Non-controlling interest in Valencia	72,348			73,546
Total equity	1,360,553			1,336,402
	$	4,637,553		$	4,473,652

The accompanying notes, as they relate to PNM, are an integral part of these financial statements.

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PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)



	Attributable to PNM
									Total PNM Common Stockholder’s Equity			Non- controlling Interest in Valencia

	Common Stock		AOCI			Retained Earnings									Total Equity
	Common Stock		AOCI			Retained Earnings									Total Equity
	(In thousands)
Balance at December 31, 2014	$	1,061,776	$	(61,755	)	$	262,835		$	1,262,856		$	73,546		$	1,336,402
Valencia’s transactions with its owner	—		—			—			—			(12,107		)	(12,107		)
Net earnings	—		—			81,014			81,014			10,909			91,923
Total other comprehensive income (loss)	—		(9,117		)	—			(9,117		)	—			(9,117		)
Dividends declared on preferred stock	—		—			(396		)	(396		)	—			(396		)
Dividends declared on common stock	—		—			(46,152		)	(46,152		)	—			(46,152		)
Balance at September 30, 2015	$	1,061,776	$	(70,872	)	$	297,301		$	1,288,205		$	72,348		$	1,360,553

The accompanying notes, as they relate to PNM, are an integral part of these financial statements.

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Electric Operating Revenues	$	83,996		$	78,958		$	232,361		$	215,574
Operating Expenses:
Cost of energy	18,547			17,402			54,637			50,167
Administrative and general	9,071			9,230			26,946			27,839
Depreciation and amortization	15,016			13,432			42,065			37,276
Transmission and distribution costs	6,290			6,191			18,604			17,655
Taxes other than income taxes	7,405			6,830			19,782			18,238
Total operating expenses	56,329			53,085			162,034			151,175
Operating income	27,667			25,873			70,327			64,399
Other Income and Deductions:
Other income	774			1,072			3,106			2,078
Other (deductions)	(102		)	(279		)	(349		)	(583		)
Net other income and deductions	672			793			2,757			1,495
Interest Charges	6,855			6,870			20,636			20,122
Earnings before Income Taxes	21,484			19,796			52,448			45,772
Income Taxes	7,795			7,441			19,200			17,081
Net Earnings	$	13,689		$	12,355		$	33,248		$	28,691

The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)



	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015		2014
	(In thousands)
Net Earnings	$	13,689	$	12,355		$	33,248	$	28,691
Other Comprehensive Income:
Fair Value Adjustment for Cash Flow Hedges:
Change in fair market value, net of income tax (expense) benefit of $0, $0, $0 and $53	—		—			—		(100		)
Reclassification adjustment for (gains) losses included in net earnings, net of income tax expense (benefit) of $0, $3, $0 and $(58)	—		(6		)	—		109
Total Other Comprehensive Income (Loss)	—		(6		)	—		9
Comprehensive Income	$	13,689	$	12,349		$	33,248	$	28,700

The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine Months Ended September 30,
	2015			2014
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	33,248		$	28,691
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization	43,272			39,577
Deferred income tax expense	3,575			4,256
Other, net	(125		)	(169		)
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues	(7,563		)	(5,376		)
Materials and supplies	(301		)	(203		)
Other current assets	2,712			1,761
Other assets	(272		)	(58		)
Accounts payable	(210		)	(1,302		)
Accrued interest and taxes	19,757			19,054
Other current liabilities	1,033			(1,217		)
Other liabilities	(5,870		)	1,397
Net cash flows from operating activities	89,256			86,411
Cash Flows From Investing Activities:
Utility plant additions	(90,497		)	(88,940		)
Net cash flows from investing activities	(90,497		)	(88,940		)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net	(5,000		)	—
Short-term borrowings (repayments) – affiliate, net	25,800			(10,300		)
Long-term borrowings	—			80,000
Repayment of long-term debt	—			(50,000		)
Dividends paid	(19,559		)	(16,336		)
Other, net	—			(835		)
Net cash flows from financing activities	1,241			2,529

Change in Cash and Cash Equivalents	—			—
Cash and Cash Equivalents at Beginning of Period	1			1
Cash and Cash Equivalents at End of Period	$	1		$	1

Supplemental Cash Flow Disclosures:
Interest paid, net of amounts capitalized	$	13,308		$	11,778
Income taxes paid (refunded), net	$	545		$	(299	)

Supplemental schedule of noncash investing and financing activities:
Changes in accrued plant additions	$	(216	)	$	1,658

The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	1	$	1
Accounts receivable	27,161		19,416
Unbilled revenues	9,397		9,579
Other receivables	1,009		2,063
Materials and supplies	3,070		2,769
Regulatory assets	1,893		3,875
Current portion of accumulated deferred income taxes	6,398		6,398
Other current assets	1,256		938
Total current assets	50,185		45,039
Other Property and Investments:
Other investments	238		242
Non-utility property	2,240		2,240
Total other property and investments	2,478		2,482
Utility Plant:
Plant in service and plant held for future use	1,235,573		1,182,112
Less accumulated depreciation and amortization	399,479		375,407
	836,094		806,705
Construction work in progress	42,535		16,538
Net utility plant	878,629		823,243
Deferred Charges and Other Assets:
Regulatory assets	127,054		133,962
Goodwill	226,665		226,665
Other deferred charges	8,186		8,850
Total deferred charges and other assets	361,905		369,477
	$	1,293,197	$	1,240,241

The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)



	September 30, 2015		December 31, 2014
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	—	$	5,000
Short-term debt – affiliate	48,500		22,700
Accounts payable	14,210		14,203
Affiliate payables	2,596		2,469
Accrued interest and taxes	48,331		28,574
Other current liabilities	3,145		2,271
Total current liabilities	116,782		75,217
Long-term Debt	365,390		365,667
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes	221,714		217,945
Regulatory liabilities	36,562		40,662
Asset retirement obligations	902		848
Accrued pension liability and postretirement benefit cost	6,979		7,888
Other deferred credits	6,514		7,349
Total deferred credits and other liabilities	272,671		274,692
Total liabilities	754,843		715,576
Commitments and Contingencies (See Note 11)
Common Stockholder’s Equity:
Common stock outstanding ($10 par value; 12,000,000 shares authorized;
issued and outstanding 6,358 shares)	64		64
Paid-in-capital	404,166		404,166
Retained earnings	134,124		120,435
Total common stockholder’s equity	538,354		524,665
	$	1,293,197	$	1,240,241

The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.

Table of Contents

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN COMMON STOCKHOLDER’S EQUITY

(Unaudited)



	Common Stock		Paid-in Capital		Retained Earnings			Total Common Stockholder’s Equity
	(In thousands)
Balance at December 31, 2014	$	64	$	404,166	$	120,435		$	524,665
Net earnings	—		—		33,248			33,248
Dividends declared on common stock	—		—		(19,559		)	(19,559		)
Balance at September 30, 2015	$	64	$	404,166	$	134,124		$	538,354

The accompanying notes, as they relate to TNMP, are an integral part of these financial statements.

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


(1)	Significant Accounting Policies and Responsibility for Financial Statements

Financial Statement Preparation

In the opinion of management, the accompanying unaudited interim Condensed Consolidated Financial Statements reflect all normal and recurring accruals and adjustments that are necessary to present fairly the consolidated financial position at September 30, 2015 and December 31, 2014 , the consolidated results of operations and comprehensive income for the three and nine months ended September 30, 2015 and 2014 , and the consolidated cash flows for the nine months ended September 30, 2015 and 2014 . The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could ultimately differ from those estimated. Weather causes the Company’s results of operations to be seasonal in nature and the results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP are so indicated. Certain amounts in the 2014 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2015 financial statement presentation.

These Condensed Consolidated Financial Statements are unaudited. Certain information and note disclosures normally included in the annual Consolidated Financial Statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these financial statements should refer to PNMR’s, PNM’s, and TNMP’s audited Consolidated Financial Statements and Notes thereto that are included in their respective 2014 Annual Reports on Form 10-K.

GAAP defines subsequent events as events or transactions that occur after the balance sheet date, but before financial statements are issued or are available to be issued. Based on their nature, magnitude, and timing, certain subsequent events may be required to be reflected at the balance sheet date and/or required to be disclosed in the financial statements. The Company has evaluated subsequent events as required by GAAP.

Principles of Consolidation

The Condensed Consolidated Financial Statements of each of PNMR, PNM, and TNMP include their accounts and those of subsidiaries in which that entity owns a majority voting interest. PNM also consolidates the PVNGS Capital Trust and Valencia. PNM owns undivided interests in several jointly-owned power plants and records its pro-rata share of the assets, liabilities, and expenses for those plants. The agreements for the jointly-owned plants provide that if an owner were to default on its payment obligations, the non-defaulting owners would be responsible for their proportionate share of the obligations of the defaulting owner. In exchange, the non-defaulting owners would be entitled to their proportionate share of the generating capacity of the defaulting owner. There have been no such payment defaults under any of the agreements for the jointly-owned plants.

PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are charged to the business segments at cost. Other significant intercompany transactions between PNMR, PNM, and TNMP include interest and income tax sharing payments, as well as equity transactions. All intercompany transactions and balances have been eliminated. See Note 14.

Dividends on Common Stock

Dividends on PNMR’s common stock are declared by its Board. The timing of the declaration of dividends is dependent on the timing of meetings and other actions of the Board. This has historically resulted in dividends considered to be attributable to the second quarter of each year being declared through actions of the Board during the third quarter of the year. The Board declared dividends on common stock considered to be for the second quarter of $0.200 per share in July 2015 and $0.185 in July 2014, which are reflected as being in the second quarter within “Dividends Declared per Common Share” on the PNMR Condensed

Table of Contents

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Consolidated Statements of Earnings. The Board declared dividends on common stock considered to be for the third quarter of $0.200 per share in September 2015 and $0.185 in September 2014, which are reflected as being in the third quarter within “Dividends Declared per Common Share” on the PNMR Condensed Consolidated Statements of Earnings.

PNM declared and paid cash dividends on common stock to PNMR of $46.2 million and $30.3 million in the nine months ended September 30, 2015 and 2014. TNMP declared and paid cash dividends of $19.6 million and $16.3 million in the nine months ended September 30, 2015 and 2014

New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company is presented below.

Accounting Standards Update 2014-09 – Revenue from Contracts with Customers (Topic 606)

On May 28, 2014, the FASB issued ASU No. 2014-09. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The ASU will replace most existing revenue recognition guidance in GAAP when it becomes effective. On August 12, 2015, the FASB issued a one-year deferral in the effective date. The Company must now adopt the new standard beginning on January 1, 2018. Early adoption would be permitted beginning January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method. The Company has not yet selected a transition method although it is unlikely the Company would elect to early adopt the new standard. The Company is analyzing the impacts this new standard will have on its consolidated financial statements and related disclosures, but has not determined the effect of the standard on its ongoing financial reporting.

Accounting Standards Update 2014-15 – Presentation of Financial Statements – Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern

On August 27, 2014, the FASB issued ASU No. 2014-15, which requires management to evaluate whether there is substantial doubt about a company’s ability to continue as a going concern in connection with the preparation of financial statements for each annual and interim reporting period. Disclosure requirements associated with management’s evaluation are also outlined in the new guidance. The new standard is effective for the Company for reporting periods ending after December 15, 2016, with early adoption permitted. The Company is analyzing the impacts of this new standard.

Accounting Standards Update 2015-03 - Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs

On April 7, 2015, the FASB issued ASU No. 2015-03, which requires that issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction of the carrying amount of that debt and not as an asset. The new standard was subsequently amended to not require a reduction of debt liabilities for issuance costs related to line-of-credit arrangements. The ASU is effective for the Company for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company is evaluating the impacts of the ASU. Currently, unamortized debt issuance costs that would be reclassified are included in other deferred charges on the Condensed Consolidated Balance Sheets and, at September 30, 2015 , amounted to $13.9 million for PNMR, $9.7 million for PNM, and $4.0 million for TNMP.

Accounting Standards Update 2015-07 - Fair Value Measurement (Topic 820): Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)

On May 1, 2015, the FASB issued ASU No. 2015-07, which removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. The new standard is effective for reporting periods beginning after December 31, 2016, with early adoption permitted. Once adopted, the update is required to be applied on a retrospective basis for all periods presented. The Company is in the process of analyzing this new standard; however, it is not expected to have a significant impact on the financial statements other than the disclosure and

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

presentation of certain investments of the Company’s employee benefit plans that are measured using the net asset value practical expedient.


(2)	Earnings Per Share

In accordance with GAAP, dual presentation of basic and diluted earnings per share is presented in the Condensed Consolidated Statements of Earnings of PNMR. Information regarding the computation of earnings per share is as follows:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(In thousands, except per share amounts)
Net Earnings Attributable to PNMR	$	61,045	$	55,653	$	107,058	$	97,262
Average Number of Common Shares:
Outstanding during period	79,654		79,654		79,654		79,654
Vested awards of restricted stock	100		112		103		134
Average Shares – Basic	79,754		79,766		79,757		79,788
Dilutive Effect of Common Stock Equivalents ⁽¹⁾ :
Stock options and restricted stock	362		457		377		491
Average Shares – Diluted	80,116		80,223		80,134		80,279
Net Earnings Per Share of Common Stock:
Basic	$	0.77	$	0.70	$	1.34	$	1.22
Diluted	$	0.76	$	0.69	$	1.34	$	1.21


⁽¹⁾	Excludes the effect of out-of-the-money options for 244,900 shares of common stock at September 30, 2015 .


(3)	Segment Information

The following segment presentation is based on the methodology that management uses for making operating decisions and assessing performance of its various business activities. A reconciliation of the segment presentation to the GAAP financial statements is provided.

PNM

PNM includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM provides integrated electricity services that include the generation, transmission, and distribution of electricity for retail electric customers in New Mexico. PNM also provides generation service to firm-requirements wholesale customers and sells electricity into the wholesale market, as well as providing transmission services to third parties. The sale of electricity into the wholesale market includes the optimization of PNM’s jurisdictional capacity, as well as the capacity from PVNGS Unit 3, which currently is not included in retail rates. FERC has jurisdiction over wholesale and transmission rates.

TNMP

TNMP is an electric utility providing regulated transmission and distribution services in Texas under the TECA. TNMP’s operations are subject to traditional rate regulation by the PUCT.

Corporate and Other

The Corporate and Other segment includes PNMR holding company activities, primarily related to corporate level debt and PNMR Services Company.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following tables present summarized financial information for PNMR by segment. PNM and TNMP each operate in only one segment. Therefore, tabular segment information is not presented for PNM and TNMP.

PNMR SEGMENT INFORMATION



	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2015
Electric operating revenues	$	333,437		$	83,996		$	—		$	417,433
Cost of energy	105,708			18,547			—			124,255
Margin	227,729			65,449			—			293,178
Other operating expenses	104,977			22,766			(3,573		)	124,170
Depreciation and amortization	29,042			15,016			3,445			47,503
Operating income	93,710			27,667			128			121,505
Interest income	1,152			—			(1		)	1,151
Other income (deductions)	5,289			672			(482		)	5,479
Net interest charges	(19,837		)	(6,855		)	(836		)	(27,528		)
Segment earnings (loss) before income taxes	80,314			21,484			(1,191		)	100,607
Income taxes	27,258			7,795			699			35,752
Segment earnings (loss)	53,056			13,689			(1,890		)	64,855
Valencia non-controlling interest	(3,678		)	—			—			(3,678		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	49,246		$	13,689		$	(1,890	)	$	61,045

Nine Months Ended September 30, 2015
Electric operating revenues	$	870,826		$	232,361		$	—		$	1,103,187
Cost of energy	299,302			54,637			—			353,939
Margin	571,524			177,724			—			749,248
Other operating expenses	312,534			65,332			(11,118		)	366,748
Depreciation and amortization	86,446			42,065			10,502			139,013
Operating income	172,544			70,327			616			243,487
Interest income	4,869			—			(27		)	4,842
Other income (deductions)	18,547			2,757			(2,935		)	18,369
Net interest charges	(59,477		)	(20,636		)	(6,601		)	(86,714		)
Segment earnings (loss) before income taxes	136,483			52,448			(8,947		)	179,984
Income taxes (benefit)	44,560			19,200			(2,139		)	61,621
Segment earnings (loss)	91,923			33,248			(6,808		)	118,363
Valencia non-controlling interest	(10,909		)	—			—			(10,909		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	80,618		$	33,248		$	(6,808	)	$	107,058

At September 30, 2015:
Total Assets	$	4,637,553		$	1,293,197		$	122,102		$	6,052,852
Goodwill	$	51,632		$	226,665		$	—		$	278,297

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	PNM			TNMP			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended September 30, 2014
Electric operating revenues	$	334,993		$	78,958		$	—		$	413,951
Cost of energy	115,097			17,402			—			132,499
Margin	219,896			61,556			—			281,452
Other operating expenses	101,757			22,251			(3,650		)	120,358
Depreciation and amortization	27,524			13,432			3,339			44,295
Operating income	90,615			25,873			311			116,799
Interest income	2,102			—			(18		)	2,084
Other income (deductions)	1,569			793			(589		)	1,773
Net interest charges	(20,092		)	(6,870		)	(3,153		)	(30,115		)
Segment earnings (loss) before income taxes	74,194			19,796			(3,449		)	90,541
Income taxes (benefit)	25,142			7,441			(1,528		)	31,055
Segment earnings (loss)	49,052			12,355			(1,921		)	59,486
Valencia non-controlling interest	(3,701		)	—			—			(3,701		)
Subsidiary preferred stock dividends	(132		)	—			—			(132		)
Segment earnings (loss) attributable to PNMR	$	45,219		$	12,355		$	(1,921	)	$	55,653

Nine Months Ended September 30, 2014
Electric operating revenues	$	873,434		$	215,574		$	—		$	1,089,008
Cost of energy	304,365			50,167			—			354,532
Margin	569,069			165,407			—			734,476
Other operating expenses	315,714			63,732			(10,243		)	369,203
Depreciation and amortization	81,629			37,276			9,519			128,424
Operating income	171,726			64,399			724			236,849
Interest income	6,295			—			(54		)	6,241
Other income (deductions)	8,749			1,495			(1,547		)	8,697
Net interest charges	(59,927		)	(20,122		)	(9,572		)	(89,621		)
Segment earnings (loss) before income taxes	126,843			45,772			(10,449		)	162,166
Income taxes (benefit)	42,331			17,081			(6,044		)	53,368
Segment earnings (loss)	84,512			28,691			(4,405		)	108,798
Valencia non-controlling interest	(11,140		)	—			—			(11,140		)
Subsidiary preferred stock dividends	(396		)	—			—			(396		)
Segment earnings (loss) attributable to PNMR	$	72,976		$	28,691		$	(4,405	)	$	97,262

At September 30, 2014:
Total Assets	$	4,358,474		$	1,216,545		$	134,190		$	5,709,209
Goodwill	$	51,632		$	226,665		$	—		$	278,297


(4)	Accumulated Other Comprehensive Income (Loss)

Information regarding accumulated other comprehensive income (loss) for the nine months ended September 30, 2015 and 2014 is as follows:

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)



	Accumulated Other Comprehensive Income (Loss)
	PNM									TNMP		PNMR
	Unrealized									Fair Value		Fair Value
	Gain on									Adjustment		Adjustment
	Available-for-			Pension						for Cash		for Cash
	Sale			Liability						Flow		Flow
	Securities			Adjustment			Total			Hedges		Hedges			Total
	(In thousands)
Balance at December 31, 2014	$	28,008		$	(89,763	)	$	(61,755	)	$	—	$	—		$	(61,755	)
Amounts reclassified from AOCI (pre-tax)	(22,552		)	4,464			(18,088		)	—		—			(18,088		)
Income tax impact of amounts reclassified	8,838			(1,749		)	7,089			—		—			7,089
Other OCI changes (pre-tax)	3,095			—			3,095			—		(704		)	2,391
Income tax impact of other OCI changes	(1,213		)	—			(1,213		)	—		276			(937		)
Net change after income taxes	(11,832		)	2,715			(9,117		)	—		(428		)	(9,545		)
Balance at September 30, 2015	$	16,176		$	(87,048	)	$	(70,872	)	$	—	$	(428	)	$	(71,300	)



Balance at December 31, 2013	$	25,748		$	(83,625	)	$	(57,877	)	$	(263	)	$	—	$	(58,140	)
Amounts reclassified from AOCI (pre-tax)	(11,544		)	3,864			(7,680		)	167			—		(7,513		)
Income tax impact of amounts reclassified	4,547			(1,524		)	3,023			(58		)	—		2,965
Other OCI changes (pre-tax)	10,202			—			10,202			(153		)	—		10,049
Income tax impact of other OCI changes	(3,946		)	—			(3,946		)	53			—		(3,893		)
Net change after income taxes	(741		)	2,340			1,599			9			—		1,608
Balance at September 30, 2014	$	25,007		$	(81,285	)	$	(56,278	)	$	(254	)	$	—	$	(56,532	)

Pre-tax amounts reclassified from AOCI related to “Unrealized Gain on Available-for-Sale Securities” are included in “Gains on available-for-sale securities” in the Condensed Consolidated Statements of Earnings. Pre-tax amounts reclassified from AOCI related to “Pension Liability Adjustment” are reclassified to “Operating Expenses – Administrative and general” in the Condensed Consolidated Statements of Earnings. For the nine months ended September 30, 2015 and 2014 , 22.4% and 23.6% of the pension amounts reclassified were capitalized into construction work in process and 2.5% and 1.7% was capitalized into other accounts. Pre-tax amounts reclassified from AOCI related to “Fair Value Adjustment for Cash Flow Hedges” are reclassified to “Interest Charges” in the Condensed Consolidated Statements of Earnings. An insignificant amount was capitalized as AFUDC. The income tax impacts of all amounts reclassified from AOCI are included in “Income Taxes” in the Condensed Consolidated Statements of Earnings.


(5)	Variable Interest Entities

GAAP determines how an enterprise evaluates and accounts for its involvement with variable interest entities, focusing primarily on whether the enterprise has the power to direct the activities that most significantly impact the economic performance of a variable interest entity. GAAP also requires continual reassessment of the primary beneficiary of a variable interest entity. Additional information concerning PNM’s variable interest entities is contained in Note 9 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Valencia

PNM has a PPA to purchase all of the electric capacity and energy from Valencia, a 158 MW natural gas-fired power plant near Belen, New Mexico, through May 2028. A third-party built, owns, and operates the facility while PNM is the sole purchaser of the electricity generated. PNM is obligated to pay fixed operations and maintenance and capacity charges in addition to variable operation and maintenance charges under this PPA. For the three and nine months ended September 30, 2015 , PNM paid $4.9 million and $14.5 million for fixed charges and $0.3 million and $0.9 million for variable charges. For the three and nine months ended September 30, 2014 , PNM paid $4.8 million and $14.4 million for fixed charges and $0.3 million and $1.0 million for variable charges. PNM does not have any other financial obligations related to Valencia. The assets of Valencia can only be used to satisfy obligations of Valencia and creditors of Valencia do not have any recourse against PNM’s assets. PNM has concluded that the third party entity that owns Valencia is a variable interest entity and that PNM is the primary beneficiary of the entity under GAAP since PNM has the power to direct the activities that most significantly impact the economic performance of Valencia and will absorb the majority of the variability in the cash flows of the plant. As the primary beneficiary, PNM consolidates the entity in its financial statements. The assets and liabilities of Valencia set forth below are immaterial to PNM and, therefore, not shown separately on the Condensed Consolidated Balance Sheets. The owner’s equity and net income of Valencia are considered attributable to non-controlling interest.

Summarized financial information for Valencia is as follows:

Results of Operations



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
	(In thousands)
Operating revenues	$	5,182		$	5,061		$	15,337		$	15,300
Operating expenses	(1,504		)	(1,360		)	(4,428		)	(4,160		)
Earnings attributable to non-controlling interest	$	3,678		$	3,701		$	10,909		$	11,140

Financial Position



	September 30,		December 31,
	2015		2014
	(In thousands)
Current assets	$	3,410	$	2,513
Net property, plant, and equipment	70,471		72,321
Total assets	73,881		74,834
Current liabilities	1,533		1,288
Owners’ equity – non-controlling interest	$	72,348	$	73,546

During the term of the PPA, PNM has the option to purchase and own up to 50% of the plant or the variable interest entity. The PPA specifies that the purchase price would be the greater of (i) 50% of book value reduced by related indebtedness or (ii) 50% of fair market value. On October 8, 2013, PNM notified the owner of Valencia that PNM may exercise the option to purchase 50% of the plant. As provided in the PPA, an appraisal process was initiated since the parties failed to reach agreement on fair market value within 60 days. Under the PPA, results of the appraisal process established the purchase price after which PNM was to determine in its sole discretion whether or not to exercise its option to purchase the 50% interest. The PPA also provides that the purchase price may be adjusted to reflect the period between the determination of the purchase price and the closing. The appraisal process determined the purchase price as of October 8, 2013 to be $85.0 million , prior to any adjustment to reflect the period through the closing date. Approval of the NMPRC and FERC would be required, which could take up to 15 months. On May 30, 2014, after evaluating its alternatives with respect to Valencia, PNM notified the owner of Valencia that PNM intended

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

to purchase 50% of the plant, subject to certain conditions. PNM’s conditions include: agreeing on the purchase price, adjusted to reflect the period between October 8, 2013 and the closing; approval of the NMPRC, including specified ratemaking treatment, and FERC; approval of the Board and PNM’s board of directors; receipt of other necessary approvals and consents; and other customary closing conditions. PNM received a letter dated June 30, 2014 from the owner of Valencia suggesting that the conditions set forth in PNM’s notification raise issues under the PPA. The owner of Valencia subsequently submitted a counter-proposal to PNM in April 2015. PNM is evaluating available options. PNM cannot predict if it will reach agreement with the owner of Valencia, if required regulatory and other approvals will be received, or if the purchase will be completed.

PVNGS Leases

PNM leases interests in Units 1 and 2 of PVNGS under arrangements, which were entered into in 1985 and 1986, that are accounted for as operating leases. PNM is not the legal or tax owner of the leased assets. The leases provided PNM with an option to purchase the leased assets at appraised value at the end of the leases. PNM does not have a fixed price purchase option and does not provide residual value guarantees. The leases also provided PNM with options to renew the leases at fixed rates set forth in the leases for two years beyond the termination of the original lease terms. The option periods on certain leases could be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets were greater than parameters set forth in the leases. See Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 6 for additional information regarding the leases and actions PNM has taken with respect to its renewal and purchase options. Under GAAP, these renewal options are considered to be variable interests in the trusts and result in the trusts being considered variable interest entities.

PNM is only obligated to make payments to the trusts for the scheduled semi-annual lease payments. As of September 30, 2015 , these payments, which, net of amounts that will be returned to PNM through its ownership in related lessor notes and the Unit 2 beneficial trust, aggregate $140.1 million , including the renewal terms of the leases that PNM has elected to renew. Under certain circumstances (for example, final shutdown of the plant, the NRC issuing specified violation orders with respect to PVNGS, or the occurrence of specified nuclear events), PNM would be required to make specified payments to the beneficial owners and take title to the leased interests. If such an event had occurred as of September 30, 2015 , PNM could have been required to pay the beneficial owners up to $205.8 million on January 15, 2016 in addition to the regularly scheduled lease payments. In such event, PNM would record the acquired assets at the lower of their fair value or the aggregate of the amount paid and PNM’s carrying value of its investment in PVNGS lessor notes. Other than as discussed in Note 6, PNM has no other financial obligations or commitments to the trusts or the beneficial owners. Creditors of the trusts have no recourse to PNM’s assets other than with respect to the contractual lease payments. PNM has no additional rights to the assets of the trusts other than the use of the leased assets. PNM has no assets or liabilities recorded on its Condensed Consolidated Balance Sheets related to the trusts other than accrued lease payments of $8.4 million at September 30, 2015 and $26.0 million at December 31, 2014 , which are included in other current liabilities on the Condensed Consolidated Balance Sheets.

PNM has evaluated the PVNGS lease arrangements, including actions taken with respect to renewal and purchase options, and concluded that it does not have the power to direct the activities that most significantly impact the economic performance of the trusts and, therefore, is not the primary beneficiary of the trusts under GAAP.

Rio Bravo, formerly known as Delta

PNM had a 20 -year PPA expiring in 2020 covering the entire output of Delta, which was a variable interest under GAAP. PNM controlled the dispatch of the generating plant, which impacted the variable payments made under the PPA and impacted the economic performance of the entity that owned Delta. This arrangement was entered into prior to December 31, 2003 and PNM was unsuccessful in obtaining the information necessary to determine if it was the primary beneficiary of the entity that owned Delta, or to consolidate that entity if it were determined that PNM was the primary beneficiary. Accordingly, PNM was unable to make those determinations and, as provided in GAAP, accounted for this PPA as an operating lease.

In December 2012, PNM entered into an agreement with the owners of Delta under which PNM would purchase the entity that owned Delta. PNM closed on the purchase on July 17, 2014 and recorded the purchase as of that date. PNM changed the name of the facility to Rio Bravo.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNM made fixed and variable payments to Delta under the PPA. For the periods from July 1, 2014 through July 17, 2014 and January 1, 2014 through July 17, 2014, PNM incurred fixed capacity charges of $0.3 million and $3.5 million and variable energy charges of $0.1 million and $0.6 million . PNM recovered the variable energy charges through its FPPAC.

PNM began including the assets, liabilities, and operations of Rio Bravo at the date of the acquisition. Prior to the acquisition, consolidation of Delta would have been immaterial to PNMR and PNM. Since all of Delta’s revenues and expenses were attributable to its PPA arrangement with PNM, the primary impact of consolidating Delta to the Condensed Consolidated Statements of Earnings of PNMR and PNM would have been to reclassify Delta’s net earnings from operating expenses and reflect such amount as earnings attributable to a non-controlling interest, without any impact to net earnings attributable to PNMR and PNM.


(6)	Lease Commitments

The Company leases office buildings, vehicles, and other equipment under operating leases. In addition, PNM leases interests in Units 1 and 2 of PVNGS and leased an interest in the EIP transmission line through April 1, 2015. All of the Company’s leases are accounted for as operating leases. Additional information concerning the Company’s lease commitments is contained in Note 7 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K, including information regarding renewal and purchase options, and actions taken by PNM under the PVNGS leases.

The PVNGS leases were scheduled to expire on January 15, 2015 for the four Unit 1 leases and January 15, 2016 for the four Unit 2 leases. The four Unit 1 leases have been extended to expire on January 15, 2023 and one of the Unit 2 leases has been extended to expire on January 15, 2024. For the other three PVNGS Unit 2 leases, PNM elected to purchase the assets underlying those leases on the expiration date of the original leases and has entered into agreements with the lessors that establish the purchase prices, representing the fair market value, to be paid on January 15, 2016 by PNM for the assets underlying the leases. The leases remain in existence and PNM will record the purchases at the termination of the leases on January 15, 2016.

PNM will pay $78.1 million for the assets underlying one of the Unit 2 leases, which is for 31.25 MW of the entitlement from PVNGS Unit 2. On September 18, 2015, PNM entered into a definitive agreement to implement the purchase by PNM of the generating capacity under this lease on January 15, 2016, at which time the purchase price will be paid by PNM and the transfer of the leased interests will take place. PNM will pay $85.2 million for the assets underlying the other two Unit 2 leases, which are for 32.76 MW of the entitlement from PVNGS Unit 2. PNMR Development is also a party to the agreement regarding these two leases, which constitutes a letter of intent providing PNMR Development with the option, subject to approval by the Board and negotiation of definitive documents, to acquire the entities that own the leased assets at any time from June 1, 2014 through January 14, 2016. PNMR does not anticipate that PNMR Development will exercise the early purchase option.

At March 31, 2015, PNM owned 60% of the EIP and leased the other 40% , under a lease that expired on April 1, 2015. Following procedures set forth in the lease, PNM and the lessor entered into a definitive agreement for PNM to exercise its option to purchase on April 1, 2015 the leased capacity at fair market value, which the parties agreed would be $7.7 million . PNM closed on the purchase on April 1, 2015 and recorded the purchase of the assets underlying the lease at that date.


(7)	Fair Value of Derivative and Other Financial Instruments

Energy Related Derivative Contracts

Overview

The primary objective for the use of derivative instruments, including energy contracts, options, and futures, is to manage price risk associated with forecasted purchases of energy and fuel used to generate electricity, as well as managing anticipated generation capacity in excess of forecasted demand from existing customers. The Company’s energy related derivative contracts manage commodity risk. PNM is required to meet the demand and energy needs of its retail and firm-requirements wholesale customers. PNM is exposed to market risk for its share of PVNGS Unit 3 and the needs of its firm-requirements wholesale customers not covered under a FPPAC. PNM’s operations are managed primarily through a net asset-backed strategy, whereby PNM’s aggregate net open forward contract position is covered by its forecasted excess generation capabilities or market purchases. PNM could be exposed to market risk if its generation capabilities were to be disrupted or if its load requirements were to be

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

greater than anticipated. If all or a portion of load requirements were required to be covered as a result of such unexpected situations, commitments would have to be met through market purchases. Additional information concerning the Company’s energy related derivative contracts, including how commodity risk is managed, is contained in Note 8 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

Commodity Risk

Marketing and procurement of energy often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. PNM routinely enters into various derivative instruments such as forward contracts, option agreements, and price basis swap agreements to economically hedge price and volume risk on power commitments and fuel requirements and to minimize the effect of market fluctuations in wholesale portfolios. PNM monitors the market risk of its commodity contracts using VaR calculations to maintain total exposure within management-prescribed limits in accordance with approved risk and credit policies.

Accounting for Derivatives

Under derivative accounting and related rules for energy contracts, the Company accounts for its various derivative instruments for the purchase and sale of energy based on the Company’s intent. During the nine months ended September 30, 2015 and the year ended December 31, 2014, the Company was not hedging its exposure to the variability in future cash flows from commodity derivatives through designated cash flows hedges. The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as economic hedges. Economic hedges are defined as derivative instruments, including long-term power agreements, used to economically hedge generation assets, purchased power and fuel costs, and customer load requirements. Changes in the fair value of economic hedges are reflected in results of operations and are classified between operating revenues and cost of energy according to the intent of the hedge. The Company has no trading transactions.

Fair value is defined under GAAP as the price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. Fair value is based on current market quotes as available and is supplemented by modeling techniques and assumptions made by the Company to the extent quoted market prices or volatilities are not available. External pricing input availability varies based on commodity location, market liquidity, and term of the agreement. Valuations of derivative assets and liabilities take into account nonperformance risk including the effect of counterparties’ and the Company’s credit risk. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although the Company uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.

Commodity Derivatives

Commodity derivative instruments that are recorded at fair value, all of which are accounted for as economic hedges, are summarized as follows:



	Economic Hedges
	September 30, 2015			December 31, 2014
PNMR and PNM	(In thousands)
Current assets	$	6,144		$	11,232
Deferred charges	3,369			—
	9,513			11,232

Current liabilities	(984		)	(1,209		)
Long-term liabilities	—			(477		)
	(984		)	(1,686		)
Net	$	8,529		$	9,546

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Included in the above table are $2.2 million of current assets and $3.4 million in deferred charges at September 30, 2015 and $3.0 million of current assets at December 31, 2014 related to contracts for the sale of energy from PVNGS Unit 3 through 2017 at market price plus a premium. Certain of PNM’s commodity derivative instruments in the above table are subject to master netting agreements whereby assets and liabilities could be offset in the settlement process. The Company does not offset fair value, cash collateral, and accrued payable or receivable amounts recognized for derivative instruments under master netting arrangements and the above table reflects the gross amounts of assets and liabilities. The amounts that could be offset under master netting agreements were immaterial at September 30, 2015 and December 31, 2014.

At September 30, 2015 and December 31, 2014 , PNMR and PNM had no amounts recognized for the legal right to reclaim cash collateral. However, at September 30, 2015 and December 31, 2014 , amounts posted as cash collateral under margin arrangements were $1.2 million and $3.8 million for both PNMR and PNM. At September 30, 2015 and December 31, 2014, obligations to return cash collateral were $0.1 million and $0.2 million , for both PNMR and PNM. Cash collateral amounts are included in other current assets and other current liabilities on the Condensed Consolidated Balance Sheets.

PNM has a NMPRC approved hedging plan to manage fuel and purchased power costs related to customers covered by its FPPAC. The table above includes $0.3 million of current assets and less than $0.1 million of current liabilities at September 30, 2015 related to this plan. The offsets to these amounts are recorded as regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. At December 31, 2014, there were no hedges in place under this plan.

The following table presents the effect of mark-to-market commodity derivative instruments on earnings, excluding income tax effects. Commodity derivatives had no impact on OCI for the periods presented.



	Economic Hedges
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
PNMR and PNM	(In thousands)
Electric operating revenues	$	6,823		$	2,352		$	7,354		$	(2,124	)
Cost of energy	(78		)	(60		)	(227		)	186
Total gain (loss)	$	6,745		$	2,292		$	7,127		$	(1,938	)

Commodity contract volume positions are presented in MMBTU for gas related contracts and in MWh for power related contracts. The table below presents PNMR’s and PNM’s net buy (sell) volume positions:



	Economic Hedges
	MMBTU	MWh
PNMR and PNM
September 30, 2015	1,227,498	(2,942,281	)
December 31, 2014	650,000	(1,919,000	)

In connection with managing its commodity risks, the Company enters into master agreements with certain counterparties. If the Company is in a net liability position under an agreement, some agreements provide that the counterparties can request collateral from the Company if the Company’s credit rating is downgraded; other agreements provide that the counterparty may request collateral to provide it with “adequate assurance” that the Company will perform; and others have no provision for collateral.

The table below presents information about the Company’s contingent requirements to provide collateral under commodity contracts having an objectively determinable collateral provision that are in net liability positions and are not fully collateralized with cash. Contractual liability represents commodity derivative contracts recorded at fair value on the balance sheet, determined on an individual contract basis without offsetting amounts for individual contracts that are in an asset position and could be offset under master netting agreements with the same counterparty. The table only reflects cash collateral that has been posted under

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

the existing contracts and does not reflect letters of credit under PNM’s revolving credit facilities that have been issued as collateral. Net exposure is the net contractual liability for all contracts, including those designated as normal purchases and normal sales, offset by existing cash collateral and by any offsets available under master netting agreements, including both asset and liability positions.



Contingent Feature – Credit Rating Downgrade	Contractual Liability		Existing Cash Collateral		Net Exposure
	(In thousands)
PNMR and PNM
September 30, 2015	$	967	$	—	$	207
December 31, 2014	$	1,686	$	—	$	167

Sale of Power from PVNGS Unit 3

Because PNM’s 134 MW share of Unit 3 at PVNGS is not currently included in retail rates, that unit’s power is being sold in the wholesale market. As of September 30, 2015 , PNM had contracted to sell 100% of PVNGS Unit 3 output through 2017, at market price plus a premium. Through hedging arrangements that are accounted for as economic hedges, PNM has established fixed rates, which average approximately $37 per MWh, for substantially all of the sales through 2015. There are currently no hedging arrangements in place for the 2016 and 2017 sales.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, receivables, and payables due to the short period of maturity. Available-for-sale securities are carried at fair value. Available-for-sale securities for PNMR and PNM consist of PNM assets held in the NDT for its share of decommissioning costs of PVNGS and a trust for PNM’s share of post-term reclamation costs related to the coal mines serving SJGS (Note 11). At September 30, 2015 and December 31, 2014 , the fair value of available-for-sale securities included $237.3 million and $244.6 million for the NDT and $5.5 million and $5.5 million for the mine reclamation trust. The fair value and gross unrealized gains of investments in available-for-sale securities are presented in the following table.



	September 30, 2015				December 31, 2014
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
PNMR and PNM			(In thousands)
Cash and cash equivalents	$	—	$	28,813	$	—	$	8,276
Equity securities:
Domestic value	11,880		42,769		17,418		45,340
Domestic growth	10,124		58,424		21,354		74,053
International and other	1		1,681		156		16,599
Fixed income securities:
U.S. Government	598		25,544		903		22,563
Municipals	3,499		61,106		5,851		68,973
Corporate and other	618		24,458		666		14,341
	$	26,720	$	242,795	$	46,348	$	250,145

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The proceeds and gross realized gains and losses on the disposition of available-for-sale securities for PNMR and PNM are shown in the following table. Realized gains and losses are determined by specific identification of costs of securities sold. Gross realized losses shown below exclude the change in realized impairment losses of $(2.4) million and $(3.2) million for the three and nine months ended September 30, 2015 and $(1.2) million and $(0.7) million for the three and nine months ended September 30, 2014.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
	(In thousands)
Proceeds from sales	$	71,576		$	29,103		$	166,097		$	82,222
Gross realized gains	$	8,998		$	3,134		$	22,463		$	11,616
Gross realized (losses)	$	(4,014	)	$	(936	)	$	(7,133	)	$	(2,731	)

Held-to-maturity securities are those investments in debt securities that the Company has the ability and intent to hold until maturity. Held-to-maturity securities consist of the investment in PVNGS lessor notes and certain items within other investments.

The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no securities impairments considered to be “other than temporary” included in AOCI. All such impairments have been recognized in earnings.

At September 30, 2015 , the available-for-sale and held-to-maturity debt securities had the following final maturities:



	Fair Value
	Available-for-Sale		Held-to-Maturity
	PNMR and PNM		PNMR		PNM
	(In thousands)
Within 1 year	$	4,558	$	8,947	$	8,947
After 1 year through 5 years	21,516		652		—
After 5 years through 10 years	23,048		—		—
After 10 years through 15 years	11,105		—		—
After 15 years through 20 years	10,593		—		—
After 20 years	40,288		—		—
	$	111,108	$	9,599	$	8,947

Fair Value Disclosures

The Company determines the fair values of its derivative and other financial instruments based on the hierarchy established in GAAP, which requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. GAAP describes three levels of inputs that may be used to measure fair value. Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. Level 3 inputs used in determining fair values for the Company consist of internal valuation models. The Company records any transfers between fair value hierarchy levels as of the end of each calendar quarter. There were no transfers between levels during the nine months ended September 30, 2015 and the year ended December 31, 2014 .

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For available-for-sale securities, Level 2 fair values are provided by the trustee utilizing a pricing service. The pricing provider predominantly uses the market approach using bid side market value based upon a hierarchy of information for specific securities or securities with similar characteristics. For commodity derivatives, Level 2 fair values are determined based on market observable inputs, which are validated using multiple broker quotes, including forward price, volatility, and interest rate curves to establish expectations of future prices. Credit valuation adjustments are made for estimated credit losses based on the overall exposure to each counterparty. For the Company’s long-term debt, Level 2 fair values are provided by an external pricing service. The pricing service primarily utilizes quoted prices for similar debt in active markets when determining fair value. For investments categorized as Level 3, primarily the PVNGS lessor notes and certain items in other investments, fair values were determined by discounted cash flow models that take into consideration discount rates that are observable for similar types of assets and liabilities. Management of the Company independently verifies the information provided by pricing services.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Items recorded at fair value on the Condensed Consolidated Balance Sheets are presented below by level of the fair value hierarchy. There were no Level 3 fair value measurements at September 30, 2015 and December 31, 2014 for items recorded at fair value.



				GAAP Fair Value Hierarchy
	Total			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)
September 30, 2015	(In thousands)
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	28,813		$	28,813	$	—
Equity securities:
Domestic value	42,769			42,769		—
Domestic growth	58,424			58,424		—
International and other	1,681			1,681		—
Fixed income securities:
U.S. Government	25,544			24,254		1,290
Municipals	61,106			—		61,106
Corporate and other	24,458			4,169		20,289
	$	242,795		$	160,110	$	82,685

Commodity derivative assets	$	9,513		$	—	$	9,513
Commodity derivative liabilities	(984		)	—		(984		)
Net	$	8,529		$	—	$	8,529

December 31, 2014
PNMR and PNM
Available-for-sale securities
Cash and cash equivalents	$	8,276		$	8,276	$	—
Equity securities:
Domestic value	45,340			45,340		—
Domestic growth	74,053			74,053		—
International and other	16,599			16,599		—
Fixed income securities:
U.S. Government	22,563			20,808		1,755
Municipals	68,973			—		68,973
Corporate and other	14,341			4,843		9,498
	$	250,145		$	169,919	$	80,226

Commodity derivative assets	$	11,232		$	—	$	11,232
Commodity derivative liabilities	(1,686		)	—		(1,686		)
Net	$	9,546		$	—	$	9,546

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The carrying amounts and fair values of investments in PVNGS lessor notes, other investments, and long-term debt, which are not recorded at fair value on the Condensed Consolidated Balance Sheets are presented below:



					GAAP Fair Value Hierarchy
	Carrying Amount		Fair Value		Level 1		Level 2		Level 3
September 30, 2015	(In thousands)
PNMR
Long-term debt	$	2,105,381	$	2,297,887	$	—	$	2,297,887	$	—
Investment in PVNGS lessor notes	$	8,824	$	8,947	$	—	$	—	$	8,947
Other investments	$	490	$	1,142	$	490	$	—	$	652
PNM
Long-term debt	$	1,589,991	$	1,719,947	$	—	$	1,719,947	$	—
Investment in PVNGS lessor notes	$	8,824	$	8,947	$	—	$	—	$	8,947
Other investments	$	252	$	252	$	252	$	—	$	—
TNMP
Long-term debt	$	365,390	$	427,940	$	—	$	427,940	$	—
Other investments	$	238	$	238	$	238	$	—	$	—

December 31, 2014
PNMR
Long-term debt	$	1,975,090	$	2,173,117	$	—	$	2,173,117	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	1,762	$	2,375	$	639	$	—	$	1,736
PNM
Long-term debt	$	1,490,657	$	1,624,222	$	—	$	1,624,222	$	—
Investment in PVNGS lessor notes	$	31,232	$	32,836	$	—	$	—	$	32,836
Other investments	$	397	$	397	$	397	$	—	$	—
TNMP
Long-term debt	$	365,667	$	427,356	$	—	$	427,356	$	—
Other investments	$	242	$	242	$	242	$	—	$	—


(8)	Stock-Based Compensation

PNMR has various stock-based compensation programs, including stock options, restricted stock, and performance shares granted under the Performance Equity Plan (“PEP”). Although certain PNM and TNMP employees participate in the PNMR plans, PNM and TNMP do not have separate employee stock-based compensation plans. In 2011, the Company changed its approach to awarding stock-based compensation. As a result, no stock options have been granted since 2010 and awards of restricted stock have increased. Certain restricted stock awards are subject to achieving performance or market targets. Other awards of restricted stock are only subject to time vesting requirements. Additional information concerning stock-based compensation under the PEP is contained in Note 13 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

Restricted stock under the PEP refers to awards of stock subject to vesting, performance, or market conditions rather than to shares with contractual post-vesting restrictions. Generally, the awards vest ratably over three years from the grant date of the award. However, certain awards with performance or market conditions vest upon satisfaction of those conditions. In addition, plan provisions provide that upon retirement, participants become 100% vested in certain stock awards.

The stock-based compensation expense related to restricted stock awards without performance or market conditions is amortized to compensation expense over the requisite vesting period, which is generally three years. However, compensation expense for awards to participants that are retirement eligible on the grant date is recognized immediately at the grant date and is not amortized. Compensation expense for performance-based shares is recognized ratably over the performance period and is

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

adjusted periodically to reflect the level of achievement expected to be attained. Compensation expense related to market-based shares is recognized ratably over the measurement period, regardless of the actual level of achievement, provided the employees meet their service requirements. At September 30, 2015 and December 31, 2014 , PNMR had unrecognized expense related to stock awards of $6.8 million and $6.5 million .

The grant date fair value of stock awards with market targets is determined using Monte Carlo simulation models, which provide grant date fair values that include an expectation of the number of shares to vest at the end of the measurement period. The grant date fair value for other restricted stock awards is determined based on the market price of PNMR common stock on the date of the agreements reduced by the present value of future dividends, which will not be received prior to vesting, applied to the total number of shares that are anticipated to vest, although the number of performance shares that ultimately vest cannot be determined until after the performance periods end.

The following table summarizes the weighted-average assumptions used to determine the awards grant date fair value:



	Nine Months Ended September 30,
Restricted Shares and Performance Based Shares	2015			2014
Expected quarterly dividends per share	$	0.200		$	0.185
Risk-free interest rate	0.92		%	0.62		%

Market-Based Shares
Dividend yield	2.87		%	2.82		%
Expected volatility	18.73		%	25.11		%
Risk-free interest rate	1.00		%	0.64		%

The following table summarizes activity in stock options and restricted stock awards, including performance-based and market-based shares, for the nine months ended September 30, 2015 :



	Restricted Stock				Stock Options
	Shares		Weighted- Average Grant Date Fair Value		Shares		Weighted- Average Exercise Price
Outstanding at December 31, 2014	258,770		$	22.31	920,505		$	20.39
Granted	340,020		$	20.34	—		$	—
Exercised	(349,468	)	$	18.61	(215,945	)	$	19.98
Forfeited	(4,061	)	$	24.81	(1,000	)	$	30.50
Expired	—		$	—	(66,201	)	$	27.90
Outstanding at September 30, 2015	245,261		$	24.81	637,359		$	19.54

PNMR’s stock-based compensation program provides for performance and market targets through 2017. Included as granted and exercised in the above table are 179,845 previously awarded shares that were earned for the 2012 through 2014 performance measurement period and approved by the Board in February 2015 (based upon achieving market targets at “target” levels, weighted at 60% , and performance targets at “maximum” levels, weighted at 40% ). Excluded from the above table, are maximums of 180,970 , 165,628 , and 168,258 shares for the three -year performance periods ending in 2015, 2016, and 2017 that would be awarded if all performance and market criteria are achieved at maximum levels and all executives remain eligible.

In March 2012, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 135,000 shares of PNMR’s common stock if PNMR meets specific market targets at the end of 2016 and she remains an employee of the Company. Under the agreement, she would receive 35,000 of the total shares if

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

PNMR achieved specific market targets at the end of 2014. The specified market target was achieved at the end of 2014 and the Board approved her receiving the 35,000 shares in February 2015, which shares are included as granted and exercised in the above table. The retention award was made under the PEP and was approved by the Board on February 28, 2012. The above table does not include the restricted stock shares that remain unvested under this retention award agreement.

Effective as of January 1, 2015, the Company entered into a retention award agreement with its Executive Vice President and Chief Financial Officer under which he would receive awards of restricted stock if PNMR meets specific performance targets at the end of 2016 and 2017 and he remains an employee of the Company. If PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2016, he would receive $100,000 of PNMR common stock based on the market value per share on the grant date, which would be in early 2017. Similarly, if PNMR achieves the specific performance target for the period from January 1, 2015 through December 31, 2017, he would receive $275,000 of PNMR common stock based on the market value per share on the grant date, which would be in early 2018. If the target for the first performance period is not met, but the target for the second performance period is met, he would receive both awards, less any amount received previously under the agreement. The retention award was made under the PEP and was approved by the Board on December 9, 2014. The above table does not include any restricted stock shares under this retention award agreement.

In March 2015, the Company entered into a retention award agreement with its Chairman, President, and Chief Executive Officer under which she would receive 53,859 shares of PNMR’s common stock if PNMR meets certain performance targets at the end of 2019 and she remains an employee of the Company. Under the agreement, she would receive 17,953 of the total shares if PNMR achieves specific performance targets at the end of 2017. The retention award was made under the PEP and was approved by the Board on February 26, 2015. The above table does not include any restricted stock shares under this retention award agreement.

At September 30, 2015 , the aggregate intrinsic value of stock options outstanding, all of which are exercisable, was $6.0 million with a weighted-average remaining contract life of 2.38 years. At September 30, 2015 , the exercise price of 244,900 outstanding stock options is greater than the closing price of PNMR common stock on that date; therefore, those options have no intrinsic value.

The following table provides additional information concerning stock options and restricted stock activity, including performance-based and market-based shares:



	Nine Months Ended September 30,
Restricted Stock	2015		2014
Weighted-average grant date fair value	$	20.34	$	21.27
Total fair value of restricted shares that vested (in thousands)	$	6,503	$	4,929

Stock Options
Weighted-average grant date fair value of options granted	$	—	$	—
Total fair value of options that vested (in thousands)	$	—	$	—
Total intrinsic value of options exercised (in thousands)	$	1,814	$	2,199


(9)	Financing

Additional information concerning financing activities, including a TNMP cash-flow hedge, which terminated on June 27, 2014, that established a fixed interest rate on a variable rate loan, is contained in Note 6 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

Financing Activities

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

On March 5, 2014, PNM entered into a $175.0 million Term Loan Agreement (the “PNM 2014 Term Loan Agreement”) among PNM and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as Lender and Administrative Agent. On March 5, 2014, PNM used a portion of the funds borrowed under the PNM 2014 Term Loan Agreement to repay all amounts outstanding under PNM’s existing $75.0 million PNM 2013 Term Loan Agreement and other short-term amounts outstanding. The PNM 2014 Term Loan Agreement was repaid on August 12, 2015.

On December 22, 2014, PNM entered into a multi-draw term loan facility (the “PNM Multi-draw Term Loan”) with JPMorgan Chase Bank, N.A., as Lender and Administrative Agent. The $125.0 million facility has a maturity date of June 21, 2016. At December 31, 2014, outstanding borrowings under the PNM Multi-draw Term Loan were $100.0 million . PNM drew the remaining capacity of $25.0 million on May 8, 2015 resulting in outstanding borrowings at September 30, 2015 of $125.0 million , which are included in current maturities of long-term debt on the Condensed Consolidated Balance Sheet. The PNM Multi-draw Term Loan bears interest at a variable rate, which was 0.78% at September 30, 2015. The PNM Multi-draw Term Loan includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-consolidated capitalization ratio and customary events of default. The PNM Multi-draw Term Loan Agreement has a cross default provision and a change of control provision.

On March 9, 2015, PNMR entered into a $150.0 million Term Loan Agreement (“PNMR 2015 Term Loan Agreement”) between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate, which was 1.21% at September 30, 2015 , and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants, including requirements to not exceed a maximum consolidated debt-to-capital ratio and customary events of default. The PNMR 2015 Term Loan Agreement has a cross default provision and a change of control provision.

At December 31, 2014, PNMR had an aggregate outstanding principal amount of $118.8 million of its 9.25% Senior Unsecured Notes, Series A, which were due on May 15, 2015. PNMR repaid all of the 9.25% Senior Unsecured Notes, Series A at the scheduled maturity, utilizing proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility.

At December 31, 2014, PNM had a $39.3 million series of outstanding Senior Unsecured Notes, Pollution Control Revenue Bonds, which have a final maturity of June 1, 2043. These PCRBs were subject to mandatory tender for remarketing on June 1, 2015 and were successfully remarketed on that date. The notes now bear interest at 2.40% , continue to have an outstanding amount of $39.3 million , and are subject to mandatory tender for remarketing on June 1, 2020.

On August 11, 2015, PNM issued $250.0 million aggregate principal amount of its 3.850% Senior Unsecured Notes due 2025. The notes will mature on August 1, 2025. Portions of the proceeds from the offering were used to repay the existing $175.0 million PNM 2014 Term Loan Agreement and to repay outstanding borrowings under the PNM Revolving Credit Facility, the PNM New Mexico Credit Facility, and PNM’s intercompany loan from PNMR.

In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 2.027% for borrowings under the PNMR 2015 Term Loan Agreement discussed above for the period from January 11, 2016 through March 9, 2018. This hedge is accounted for as a cash-flow hedge and had a fair value loss of $0.7 million at September 30, 2015, using Level 2 inputs under GAAP determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.

Short-term Debt

The PNMR Revolving Credit Facility has a financing capacity of $300.0 million and the PNM Revolving Credit Facility has a financing capacity of $400.0 million . In October 2015, the maturity date for both of these facilities was extended and they now mature on October 31, 2020. The TNMP Revolving Credit Facility is a $75.0 million revolving credit facility secured by $75.0 million aggregate principal amount of TNMP first mortgage bonds. The TNMP Revolving Credit Facility matures on September 18, 2018. PNM also has the $50.0 million PNM New Mexico Credit Facility that expires on January 8, 2018. At September 30, 2015 , TNMP had $48.5 million in borrowings from PNMR under an intercompany loan agreement. At September 30, 2015 , the weighted average interest rate was 1.69% for the PNMR Revolving Credit Facility and 1.05% for borrowings outstanding

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(Unaudited)

under the twelve-month PNMR Term Loan Agreement, which matures in December 2015. Short-term debt outstanding consisted of:



	September 30,		December 31,
Short-term Debt	2015		2014
	(In thousands)
PNM:
Revolving credit facility	$	—	$	—
PNM New Mexico Credit Facility	—		—
TNMP – Revolving credit facility	—		5,000
PNMR:
Revolving credit facility	2,600		600
PNMR Term Loan Agreement	100,000		100,000
	$	102,600	$	105,600

At October 23, 2015 , PNMR, PNM, and TNMP had $293.8 million , $396.8 million , and $54.9 million of availability under their respective revolving credit facilities, including reductions of availability due to outstanding letters of credit, and PNM had $50.0 million of availability under the PNM New Mexico Credit Facility. Total availability at October 23, 2015 , on a consolidated basis, was $795.5 million for PNMR. As of October 23, 2015 , TNMP had $36.8 million in borrowings from PNMR under an intercompany loan agreement. At October 23, 2015 , PNMR, PNM and TNMP had consolidated invested cash of $11.0 million , $34.1 million , and none .


(10)	Pension and Other Postretirement Benefit Plans

PNMR and its subsidiaries maintain qualified defined benefit pension plans, postretirement benefit plans providing medical and dental benefits, and executive retirement programs (collectively, the “PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans.

Additional information concerning pension and OPEB plans is contained in Note 12 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. Annual net periodic benefit cost (income) for the plans is actuarially determined using the methods and assumptions set forth in that note and is recognized ratably throughout the year.

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(Unaudited)

PNM Plans

The following tables present the components of the PNM Plans’ net periodic benefit cost:



	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	51		$	45		$	—	$	—
Interest cost	7,064			7,541			1,022			1,159			190		205
Expected return on plan assets	(9,831		)	(9,511		)	(1,403		)	(1,410		)	—		—
Amortization of net (gain) loss	3,705			3,255			491			556			81		52
Amortization of prior service cost	(241		)	(241		)	(160		)	(336		)	—		—
Net periodic benefit cost	$	697		$	1,044		$	1		$	14		$	271	$	257

	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost
Service cost	$	—		$	—		$	153		$	136		$	—	$	—
Interest cost	21,191			22,622			3,067			3,473			570		616
Expected return on plan assets	(29,492		)	(28,533		)	(4,208		)	(4,229		)	—		—
Amortization of net (gain) loss	11,115			9,765			1,474			1,669			243		157
Amortization of prior service cost	(724		)	(724		)	(481		)	(1,008		)	—		—
Net periodic benefit cost	$	2,090		$	3,130		$	5		$	41		$	813	$	773

PNM made contributions to its pension plan trust of zero and $30.0 million in the three and nine months ended September 30, 2015 and made no contributions in the three and nine months ended September 30, 2014 . PNM does not anticipate making additional contributions to its pension trust in 2015 . Based on current law, including recent amendments to funding requirements, and estimates of portfolio performance, contributions to the PNM pension plan trust for 2016-2019 are estimated to total $22.0 million . These anticipated contributions were developed using current funding assumptions, with discount rates of 4.8% to 5.5% . Actual amounts required to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. PNM may make additional contributions at its discretion. PNM made contributions to the OPEB trust of $0.8 million and $2.4 million in the three and nine months ended September 30, 2015 and $0.8 million and $2.4 million in the three and nine months ended September 30, 2014 . PNM expects to make contributions to the OPEB trust totaling $3.5 million in 2015 and $14.0 million for 2016-2019. Disbursements under the executive retirement program, which are funded by PNM and considered to be contributions to the plan, were $0.4 million and $1.2 million in the three and nine months ended September 30, 2015 and $0.4 million and $1.2 million in the three and nine months ended September 30, 2014 and are expected to total $1.5 million during 2015 .

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(Unaudited)

TNMP Plans

The following tables present the components of the TNMP Plans’ net periodic benefit cost (income):



	Three Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	62		$	59		$	—	$	—
Interest cost	761			798			152			155			9		10
Expected return on plan assets	(1,105		)	(1,132		)	(130		)	(133		)	—		—
Amortization of net (gain) loss	195			166			—			(31		)	1		—
Amortization of prior service cost	—			—			—			8			—		—
Net Periodic Benefit Cost (Income)	$	(149	)	$	(168	)	$	84		$	58		$	10	$	10

	Nine Months Ended September 30,
	Pension Plan						OPEB Plan						Executive Retirement Program
	2015			2014			2015			2014			2015		2014
	(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	—		$	—		$	185		$	178		$	—	$	—
Interest cost	2,282			2,395			456			464			27		29
Expected return on plan assets	(3,315		)	(3,395		)	(390		)	(400		)	—		—
Amortization of net (gain) loss	586			499			—			(92		)	3		—
Amortization of prior service cost	—			—			—			24			—		—
Net Periodic Benefit Cost (Income)	$	(447	)	$	(501	)	$	251		$	174		$	30	$	29

TNMP made no contribution to its pension trust in 2014 and does not anticipate making any contributions in 2015 -2019 based on current law, including recent amendments to funding requirements, and estimates of portfolio performance. These expectations were developed using current funding assumptions, including discount rates of 4.8% and 5.5% . Actual amounts to be funded in the future will depend on the actuarial assumptions at that time, including the appropriate discount rate. TNMP may make additional contributions at its discretion. TNMP made no contributions to the OPEB trust in the nine months ended September 30, 2015 and zero and $0.3 million in the three and nine months ended September 30, 2014 . TNMP expects to make contributions to the OPEB trust totaling $0.3 million in 2015 and $1.4 million for 2016-2019. Disbursements under the executive retirement program, which are funded by TNMP and considered to be contributions to the plan, were less than $0.1 million in the three and nine months ended September 30, 2015 and 2014 and are expected to total $0.1 million during 2015 .


(11)	Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company also is subject to federal, state, and local environmental laws and regulations and periodically participates in the investigation and remediation of various sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. Also, the

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(Unaudited)

Company is involved in various legal and regulatory (Note 12) proceedings in the normal course of its business. It is not possible at this time for the Company to determine fully the effect of all litigation and other legal and regulatory proceedings on its financial position, results of operations, or cash flows.

With respect to some of the items listed below, the Company has determined that a loss is not probable or that, to the extent probable, cannot be reasonably estimated. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Nevertheless, the Company assesses legal and regulatory matters based on current information and makes judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of any damages sought, and the probability of success. Such judgments are made with the understanding that the outcome of any litigation, investigation, and other legal proceeding is inherently uncertain. In accordance with GAAP, the Company records liabilities for matters where it is probable a loss has been incurred and the amount of loss is reasonably estimable. The actual outcomes of the items listed below could ultimately differ from the judgments made and the differences could be material. The Company cannot make any assurances that the amount of reserves or potential insurance coverage will be sufficient to cover the cash obligations that might be incurred as a result of litigation or regulatory proceedings. Except as otherwise disclosed, the Company does not expect that any known lawsuits, environmental costs, and commitments will have a material effect on its financial condition, results of operations, or cash flows.

Additional information concerning commitments and contingencies is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

Commitments and Contingencies Related to the Environment

Nuclear Spent Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE that require the DOE to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE announced that it would not be able to open the repository by 1998 and sought to excuse its performance of these requirements. In November 1997, the D.C. Circuit issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other PVNGS owners, including PNM), filed damages actions against the DOE in the Court of Federal Claims. In 2010, the court ordered an award to the PVNGS owners for their damages claim for costs incurred through December 2006. APS filed a subsequent lawsuit, on behalf of itself and the other PVNGS owners, against DOE in the Court of Federal Claims on December 19, 2012. The lawsuit alleged that from January 1, 2007 through June 30, 2011, additional damages were incurred due to DOE’s continuing failure to remove spent nuclear fuel and high level waste from PVNGS. APS and DOE entered into a settlement agreement, and on October 7, 2014, APS received a settlement payment of $57.4 million for costs paid through June 30, 2011, for DOE’s failure to accept spent nuclear fuel generated at PVNGS. PNM’s share of the settlement was $5.9 million , substantially all of which was credited back to PNM’s customers. The settlement agreement also establishes a process for the payment of subsequent claims through December 31, 2016. Under the settlement agreement, APS must submit claims annually for payment of allowable costs. The settlement agreement terminates upon payment of costs paid through December 31, 2016, unless extended by mutual written agreement. On October 31, 2014, APS submitted a claim for costs paid between July 1, 2011 and June 30, 2014 and agreed to a settlement amount of $42.0 million in March 2015. PNM’s share of the settlement, which amounted to $4.3 million , including $3.1 million credited back to PNM’s customers, was recorded in the three months ended March 31, 2015. APS anticipates submitting a $12.3 million claim in the fourth quarter of 2015 for costs paid between July 1, 2014 and June 30, 2015. In the three months ended June 30, 2015, PNM recorded claims of $1.3 million , including $0.5 million credited back to PNM’s customers, for costs paid between July 1, 2014 and June 30, 2015. Thereafter, PNM began recording estimated claims quarterly.

PNM estimates that it will incur approximately $58.0 million (in 2013 dollars) for its share of the costs related to the on-site interim storage of spent nuclear fuel at PVNGS during the term of the operating licenses. PNM accrues these costs as a component of fuel expense as the fuel is consumed. At September 30, 2015 and December 31, 2014, PNM had a liability for interim storage costs of $12.0 million and $12.3 million included in other deferred credits.

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(Unaudited)

On June 8, 2012, the D.C. Circuit issued its decision on a challenge by several states and environmental groups of the NRC’s rulemaking regarding temporary storage and permanent disposal of high level nuclear waste and spent nuclear fuel. The petitioners had challenged the NRC’s 2010 update to the agency’s Waste Confidence Decision and temporary storage rule (the “Waste Confidence Decision”). The D.C. Circuit found that the Waste Confidence Decision update constituted a major federal action, which, consistent with NEPA, requires either an environmental impact statement or a finding of no significant impact from the NRC’s actions. The D.C. Circuit found that the NRC’s evaluation of the environmental risks from spent nuclear fuel was deficient, and therefore remanded the Waste Confidence Decision update for further action consistent with NEPA. On September 6, 2012, the NRC commissioners issued a directive to the NRC staff to proceed with development of a generic EIS to support an updated Waste Confidence Decision.

In September 2013, the NRC issued its draft generic EIS to support an updated Waste Confidence Decision. On August 26, 2014, the NRC approved a final rule on the environmental effects of continued storage of spent nuclear fuel. The continued storage rule adopted the findings of the generic EIS regarding the environmental impacts of storing spent fuel at any reactor site after the reactor’s licensed period of operations. As a result, those generic impacts do not need to be re-analyzed in the environmental reviews for individual licenses. Although PVNGS had not been involved in any licensing actions affected by the D.C. Circuit’s June 8, 2012 decision, the NRC lifted its suspension on final licensing actions on all nuclear power plant licenses and renewals that went into effect when the D.C. Circuit issued its June 2012 decision. The August 2014 final rule has been subject to continuing legal challenges before the NRC and the United States Court of Appeals. PNM is unable to predict the outcome of this matter.

PVNGS has sufficient capacity at its on-site ISFSI to store all of the nuclear fuel that will be irradiated during the initial operating license period, which ends in December 2027. Additionally, PVNGS has sufficient capacity at its on-site ISFSI to store a portion of the fuel that will be irradiated during the period of extended operation, which ends in November 2047. If uncertainties regarding the United States government’s obligation to accept and store spent fuel are not favorably resolved, APS will evaluate alternative storage solutions that may obviate the need to expand the ISFSI to accommodate all of the fuel that will be irradiated during the period of extended operation.

In 2011, the National Association of Regulatory Utility Commissioners and the Nuclear Energy Institute challenged DOE’s 2010 determination of the adequacy of the one tenth of a cent per KWh fee (the “one-mill fee”) paid by the nation’s commercial nuclear power plant owners pursuant to their individual contracts with the DOE. In June 2012, the D.C. Circuit held that DOE failed to conduct a sufficient fee analysis in making the 2010 determination. The D.C. Circuit remanded the 2010 determination to the DOE with instructions to conduct a new fee adequacy determination within six months. In February 2013, upon completion of DOE’s revised one-mill fee adequacy determination, the court reopened the proceedings. On November 19, 2013, the D.C. Circuit ordered the DOE to notify Congress of DOE’s intention to suspend collecting annual fees for nuclear waste disposal from nuclear power plant operators. On January 3, 2014, the DOE notified Congress of its intention to suspend collection of the one-mill fee, subject to Congress’ disapproval. On May 16, 2014, the DOE adjusted the fee to zero . PNM anticipates challenges to this action and is unable to predict its ultimate outcome.

The Clean Air Act

Regional Haze

In 1999, EPA developed a regional haze program and regional haze rules under the CAA. The rule directs each of the 50 states to address regional haze. Pursuant to the CAA, states have the primary role to regulate visibility requirements by promulgating SIPs. States are required to establish goals for improving visibility in national parks and wilderness areas (also known as Class I areas) and to develop long-term strategies for reducing emissions of air pollutants that cause visibility impairment in their own states and for preventing degradation in other states. States must establish a series of interim goals to ensure continued progress. The first planning period specifies setting reasonable progress goals for improving visibility in Class I areas by the year 2018. In July 2005, EPA promulgated its final regional haze rule guidelines for states to conduct BART determinations for certain covered facilities, including utility boilers, built between 1962 and 1977 that have the potential to emit more than 250 tons per year of visibility impairing pollution. If it is demonstrated that the emissions from these sources cause or contribute to visibility impairment in any Class I area, then BART must be installed by 2018.

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(Unaudited)

SJGS

BART Determination Process – SJGS is a source that is subject to the statutory obligations of the CAA to reduce visibility impacts. The State of New Mexico submitted its SIP on the regional haze and interstate transport elements of the visibility rules for review by EPA in June 2011. The SIP found that BART to reduce NOx emissions from SJGS is selective non-catalytic reduction technology (“SNCR”). Nevertheless, in August 2011, EPA published its FIP, stating that it was required to do so by virtue of a consent decree it had entered into with an environmental group in litigation concerning the interstate transport requirements of the CAA. The FIP included a regional haze BART determination for SJGS that required installation of selective catalytic reduction technology (“SCR”) on all four units by September 21, 2016. In November 2012, EPA approved all components of the SIP, except for the NOx BART determination for SJGS, which continued to be subject to the FIP.

PNM, the Governor of New Mexico, and NMED petitioned the Tenth Circuit to review EPA’s decision and requested EPA to reconsider its decision. The Tenth Circuit denied petitions to stay the effective date of the rule. These parties also formally asked EPA to stay the effective date of the rule. Several environmental groups intervened in support of EPA. Although the parties filed periodic status reports with the Tenth Circuit, the proceedings were being held in abeyance as agreed to by the parties. In August 2015, the Tenth Circuit dismissed this matter on mootness grounds.

During 2012 and early 2013, PNM, as the operating agent for SJGS, engaged in discussions with NMED and EPA regarding an alternative to the FIP and SIP. Following approval by a majority of the other SJGS owners, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by the later of January 31, 2016 or 15 months after EPA approval of a revised SIP.

In accordance with the revised plan, PNM submitted a new BART analysis to NMED on April 1, 2013 and NMED developed a RSIP, both of which reflect the terms of the non-binding agreement. The EIB approved the RSIP in September 2013 and it was submitted to EPA for approval in October 2013. Final rules approving the RSIP and withdrawing the FIP were published in the Federal Register on October 9, 2014 and became effective on November 10, 2014.

Conversion of SJGS Units 1 and 4 to balanced draft technology (“BDT”) is included with the installation of SNCRs in the RSIP. The requirement to install BDT was made binding and enforceable in the NSR permit that accompanied the RSIP submitted to the EPA. EPA’s rule approving the RSIP specifically references the NSR permit by including a condition that requires “modification of the fan systems on Units 1 and 4 to achieve ‘balanced’ draft configuration ….”

Implementation Activities – Due to the compliance deadline set forth in the FIP, PNM took steps to commence installation of SCRs at SJGS. In October 2012, PNM entered into a contract with an engineering, procurement, and construction contractor to install SCRs on behalf of the SJGS owners. At the time PNM entered into the contract, PNM estimated the total cost to install SCRs on all four units of SJGS to be between approximately $824 million and $910 million . The costs for the project to install SCRs encompassed installation of BDT equipment to comply with the NAAQS requirements described below. The construction contract was terminated in December 2014 following approval of the RSIP by EPA.

Also, PNM had previously indicated it estimated the cost of SNCRs on all four units of SJGS to be between approximately $85 million and $90 million based on a conceptual design study. Along with the SNCR installation, additional BDT equipment would be required to be installed to meet the NAAQS requirements described below, the cost of which had been estimated to total between approximately $105 million and $110 million for all four units of SJGS.

The above estimates include gross receipts taxes, AFUDC, and other PNM costs. Based upon its current SJGS ownership interest, PNM’s share of the costs described above would have been about 46.3% .

Following the February 2013 development of the alternative BART compliance plan, PNM began taking steps to prepare for the potential installation of SNCR and BDT equipment on Units 1 and 4 due to the long lead times on certain equipment purchases. In May 2013, PNM entered into an equipment and related services contract with a technology provider. In July 2014, PNM entered into a contract for management of the construction and in September 2014 entered into a construction and procurement

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(Unaudited)

contract. PNM anticipates installation of SNCRs and BDT equipment will be completed within the timeframe contained in the RSIP.

NMPRC Filing – On December 20, 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. In this filing, PNM requested:


•	Permission to retire SJGS Units 2 and 3 at December 31, 2017 and to recover over 20 years their net book value at that date along with a regulated return on those costs


•	A CCN to include PNM’s ownership of PVNGS Unit 3, amounting to 134 MW, as a resource to serve New Mexico retail customers at a proposed value of $2,500 per KW, effective January 1, 2018


•	An order allowing cost recovery for PNM’s share of the installation of SNCR and BDT equipment to comply with NAAQS requirements on SJGS Units 1 and 4, not to exceed a total cost of $82 million


•	A CCN for an exchange of capacity out of SJGS Unit 3 and into SJGS Unit 4, resulting in ownership of an additional 78 MW in Unit 4 for PNM; the net impact of this exchange and the retirement of Units 2 and 3 would have been a reduction of 340 MW in PNM’s ownership of SJGS

The December 20, 2013 NMPRC filing identified a new 177 MW natural gas-fired generation source and 40 MW of new utility-scale solar PV generation to replace a portion of PNM’s share of the reduction in generating capacity due to the retirement of SJGS Units 2 and 3. PNM received approval to construct the 40 MW of solar PV facilities in its 2015 Renewable Energy Plan. See Note 12 for additional information regarding the 40 MW of solar PV facilities and a CCN for the gas facility. Although operating costs would be reduced due to the retirement of SJGS Units 2 and 3, the operating costs for SJGS Units 1 and 4 would increase with the installation of SNCR and BDT equipment.

PNM’s requests in the December 20, 2013 NMPRC filing were based on the status of the negotiations among the SJGS owners at that time regarding ownership restructuring and other matters (see SJGS Ownership Restructuring Matters below). In July 2014, PNM filed a notice with the NMPRC regarding the status of the negotiations among the SJGS participants, including that the SJGS participants reached non-binding agreements in principle on the ownership restructuring of SJGS and that PNM was proposing to acquire 132 MW of SJGS Unit 4 effective December 31, 2017, rather than exchanging 78 MW of capacity in SJGS Unit 3 for 78 MW in SJGS Unit 4 as contemplated in the December 20, 2013 NMPRC filing. Those agreements were memorialized in the resolution and term sheet described below.

On October 1, 2014, PNM, the staff of the NMPRC, the NMAG, New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico filed a stipulation with the NMPRC. NMIEC subsequently joined the agreement. New Mexico Independent Power Producers, Western Resource Advocates, and Renewable Energy Industries Association of New Mexico subsequently withdrew from the stipulation. Statements of opposition were filed by other intervenors.

Under the terms of the stipulation, PNM:


•	Would be authorized to abandon SJGS Units 2 and 3 effective December 31, 2017


•	Would be granted a CCN for an additional 132 MW of SJGS Unit 4 capacity as of January 1, 2018 with a rate base value of $26 million plus any reasonable and prudent investments made in Unit 4 prior to that date; PNM would reduce its carrying value of SJGS Unit 3 by this $26 million


•	Would recover 50% of the estimated $231 million (reflecting the $26 million transfer to SJGS Unit 4) undepreciated value in SJGS Units 2 and 3 at December 31, 2017; recovery would be over a 20 year period and would include a return on the unrecovered amount at PNM’s WACC

•

Would be granted a CCN for 134 MW of PVNGS Unit 3 at a January 1, 2018 value of $221.1 million ( $1,650 per KW); PNM’s ownership share of PVNGS would also be subject to a capacity factor performance threshold of 75% for a seven year period beginning January 1, 2018; subject to certain exceptions, if the capacity factor is not achieved in any year, PNM would refund the cost of replacement power through its FPPAC

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•	Would file for recovery of its reasonable and prudent costs of installation of the SNCR and BDT equipment requirements at SJGS Units 1 and 4 up to $90.6 million


•	Would not be allowed to recover a total of approximately $20 million of increased operations and maintenance costs associated with the agreement reached with the remaining SJGS participants, additional fuel handling expenses, and certain other costs incurred in efforts to comply with the CAA

A public hearing in the NMPRC case was held in January 2015. In connection with the hearing, PNM filed testimony indicating that:


•	PNM would not acquire the 65 MW of capacity in SJGS Unit 4 that was no longer anticipated to be acquired by the City of Farmington, as discussed under SJGS Ownership Restructuring Matters below


•	PNM would not enter into a coal supply agreement for SJGS that extends beyond 2022 without NMPRC approval


•	PNM would have an ownership restructuring agreement for SJGS in place by May 1, 2015

If this stipulation had been approved as filed, PNM estimated it would have incurred a regulatory disallowance that would include the write-off of 50% of the undepreciated investment in SJGS Units 2 and 3, an offset to the regulatory disallowance to reflect including the investment in PVNGS Unit 3 in the ratemaking process at the stipulated value, and other impacts of the stipulation. The regulatory disallowance would have been recorded upon approval by the NMPRC and satisfaction of any material conditions precedent. Based on the provisions of the stipulation as filed and PNM’s projection of December 31, 2017 book values, PNM estimated the net pre-tax regulatory disallowance would have been between $60 million and $70 million .

On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. The certification recommends that the abandonment of SJGS Units 2 and 3 be conditionally approved subject to PNM proposing adequate replacement capacity, approval of the CCN for PVNGS Unit 3 at its net book value on December 31, 2017, approval of recovery of an estimated $128.5 million (without any amounts being transferred between units), representing 50% of the remaining undepreciated investment in SJGS Units 2 and 3 at December 31, 2017, and denial of the CCN for the additional 132 MW of Unit 4 of SJGS. The certification states that PNM may re-apply for a CCN for the 132 MW after it has presented final restructuring and post-2017 coal supply agreements for SJGS. On April 20, 2015, PNM filed exceptions to the certification. PNM argued that the proposed modifications to the stipulation do not balance customer and shareholder interests, upset the balance contained in the stipulation, that the schedule recommended by the Hearing Examiner for PNM to file a replacement plan would effectively preclude the inclusion of the 132 MW of additional SJGS Unit 4 capacity in the replacement plan thereby jeopardizing the restructuring agreement and the continued operation of SJGS to the detriment of customers, and that the Hearing Examiner erred in recommending a lower rate base value for PNM’s share of PVNGS Unit 3. If the NMPRC were to issue an order adopting all of the modifications to the stipulation recommended by the Hearing Examiner, PNM estimated the net pre-tax regulatory disallowance referenced above would be between $145 million and $155 million . Except as noted below, the NMPRC has not acted on the stipulation or certification.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of confidential, substantially final, unexecuted restructuring, coal supply, and related agreements for SJGS. See SJGS Ownership Restructuring Matters and Coal Supply below. On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015. The order provided that PNM could request an extension of the required filing date to August 1, 2015 if such request was based on specific and verifiable facts. PNM subsequently requested an extension, citing that certain of the owners of SJGS were governmental entities and required the additional time in order to meet statutory public notice and meeting requirements. The NMPRC granted PNM an extension to August 1, 2015 to file the executed restructuring agreement. On July 1, 2015, PNM filed the executed coal supply and related agreements described under Coal Supply below with the NMPRC. On July 1, 2015, PNM also filed partially executed agreements related to restructuring discussed under SJGS Ownership Restructuring Matters below. On July 31, 2015, PNM filed fully executed restructuring agreements, along with testimony supporting the agreements and a CCN for the 132 MW of additional SJGS Unit 4 capacity.

In June 2015, a NMPRC Commissioner issued an order designating a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. On August 13, 2015, as a result of the facilitation process, PNM, the staff of the NMPRC, the NMAG, Western Resource Advocates, and the Coalition for Clean Affordable Energy filed a settlement agreement (the “Supplemental Stipulation”) with the NMPRC. NMIEC, Interwest Energy Alliance, and New

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Mexico Independent Power Producers subsequently joined in the Supplemental Stipulation. NEE opposes the Supplemental Stipulation. The stipulating parties agreed that the October 2014 stipulation described above should be approved, as modified by the Supplemental Stipulation (collectively, the “Stipulated Settlement”). Under the terms of the Stipulated Settlement:


•	PNM would retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) at December 31, 2017 and recover, over 20 years, 50% (estimated to be approximately $128.5 million ) of their undepreciated net book value at that date and earn a regulated return on those costs


•	PNM would be granted an unconditional CCN for 132 MW in SJGS Unit 4, with an initial book value of zero , plus the costs of SNCR and other capital additions


•	No later than December 31, 2018, and before entering into an agreement for post-2022 coal supply for SJGS, PNM would file its position and supporting testimony in an NMPRC case to determine the extent to which SJGS should continue serving PNM’s retail customers’ needs after mid-2022; all parties agree to support this case being decided within six months


•	PNM would be authorized to acquire 65 MW of SJGS Unit 4 as excluded utility plant; PNM and PNMR commit that no further coal-fired merchant plant will be acquired at any time by PNM, PNMR, or any PNM affiliate; PNM is not precluded from seeking a CCN to include the 65 MW or other coal capacity in rate base

•

Beginning January 1, 2020, for every MWh produced by 197 MW of coal-fired generation from SJGS Unit 4, PNM will acquire and retire one MWh of RECs or allowances that include a zero-CO ₂ emission attribute compliant with EPA’s Clean Power Plan; this REC retirement is in addition to what is required to meet the RPS; the cost of these RECs are to be capped at $7.0 million per year and will be recovered in rates; PNM should purchase EPA-compliant RECs from New Mexico renewable generation unless those RECs are more costly


•	PNM will accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022; cost recovery for PNM’s BDT project on those units will be determined in PNM’s next general rate case consistent with the Certification of Stipulation


•	PNM would be granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017, including transmission assets associated with PVNGS Unit 3, (estimated to be approximately $150 million )


•	Not recover approximately $20 million of other costs incurred in connection with CAA compliance


•	PNM’s 2014 IRP docket will be closed without other NMPRC action

If the NMPRC issues an order that modifies the Stipulated Settlement, any stipulating party can void it. Given the terms of this agreement, ABCWUA withdrew its opposition to the original stipulation and its pending motion to void the Capacity Option and Funding Agreement (“COFA”) discussed below. However, NEE filed a motion to void the COFA.

Approval of the NMPRC is required in order for the Stipulated Settlement to become effective. The Hearing Examiner scheduled a hearing on PNM’s application concerning BART for SJGS to begin on October 13, 2015. The hearing on the Stipulated Settlement was held from October 13, 2015 through October 20, 2015.

NEE previously filed motions before the NMPRC requesting that four of the five NMPRC commissioners recuse themselves, alleging they had improper ex-parte communications, were biased, and had pre-judged the outcome of the BART case. Each of the four commissioners declined to recuse themselves. On October 5, 2015, NEE filed a Petition for a Writ of Mandamus and Request for Stay in the NMSC requesting the four commissioners be recused from this case and that PNM’s application be dismissed. On October 9, 2015, the NMSC issued orders that allowed the hearing conducted by the Hearing Examiner to proceed, but ordered that any action by the NMPRC be stayed, pending a decision by the NMSC on NEE’s petition.

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PNM filed its response in opposition to NEE’s petition on October 27, 2015 and oral argument before the NMSC is scheduled for November 9, 2015. PNM anticipates the NMSC will issue a timely ruling on NEE’s petition. If the court denies NEE’s petition, PNM expects the NMPRC would be able to render a decision before December 31, 2015. PNM believes that NEE’s petition does not satisfy the legal requirements for a writ of mandamus. PNM believes that if the NMSC mandates recusal, the “Rule of Necessity” should be applied and that the NMSC should direct the recused commissioners to rule on the BART case and render a decision.

If the NMPRC does not approve the shutdown of SJGS Units 2 and 3, SJGS would not be able to comply with the RSIP after December 31, 2017. PNM is unable to predict the outcome of the NMSC proceeding, what action the NMPRC will take or when it will take such action, whether any party will void the Stipulated Settlement, or the ultimate outcome of this matter.

If the Stipulated Settlement is approved by the NMPRC, PNM would record a regulatory disallowance upon satisfaction of any material conditions precedent. At September 30, 2015, PNM’s net book value of its current ownership share of SJGS Units 2 and 3 was approximately $279 million and its net book value of PVNGS Unit 3 was approximately $147 million . PNM estimates the undepreciated value in SJGS Units 2 and 3 at December 31, 2017 will be approximately $257 million , 50% of which would be recovered over a 20 year period, including a return on the unrecovered amount at PNM’s WACC. PNM currently estimates the net book value of PVNGS Unit 3 at December 31, 2017 will be approximately $150 million ( $1,118 per KW). If the NMPRC were to issue an order adopting all of the provisions of the Stipulated Settlement, PNM estimates the net pre-tax regulatory disallowance would be an amount between $145 million and $155 million although the amount of the disallowance would be dependent on the provisions of the NMPRC’s final order and PNM’s projections of the December 31, 2017 net book values of SJGS Units 2 and 3. The amount initially recorded would be subject to adjustment to reflect changes in the projected December 31, 2017 net book values.

SJGS Ownership Restructuring Matters – As discussed in the 2014 Annual Report on Form 10-K, SJGS is jointly owned by PNM and eight other entities, including three participants that operate in the State of California. Furthermore, each participant does not have the same ownership interest in each unit. The SJPPA that governs the operation of SJGS expires on July 1, 2022 and the currently effective contract with SJCC to supply the coal requirements of the plant expires on December 31, 2017. The California participants have indicated that, under California law, they may be prohibited from making significant capital improvements to SJGS. The California participants stated they would be unable to fully fund the construction of either SCRs or SNCRs at SJGS and expressed the intent to exit their ownership in SJGS no later than the expiration of the current SJPPA. One other participant also expressed a similar intent to exit ownership in the plant. The participants intending to exit ownership in SJGS currently own 50.0% of SJGS Unit 3 and 38.8% of SJGS Unit 4. PNM currently owns 50.0% of SJGS Unit 3 and 38.5% of SJGS Unit 4.

The SJGS participants engaged in mediated negotiations concerning the implementation of the RSIP to address BART at SJGS. These negotiations initially included potential shifts in ownership among participants and between Units 3 and 4 that could have resulted in PNM acquiring additional ownership in SJGS Unit 4 prior to the shutdown of Units 2 and 3. The discussions among the SJGS participants regarding restructuring also included, among other matters, the treatment of plant decommissioning obligations, mine reclamation obligations, environmental matters, and certain ongoing operating costs.

On June 26, 2014, a non-binding resolution (the “Resolution”) was unanimously approved by the SJGS Coordination Committee. The Resolution identifies the participants who would be exiting active participation in SJGS effective December 31, 2017 and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. The Resolution provides the essential terms of restructured ownership of SJGS between the exiting participants and the remaining participants and addresses other related matters. The Resolution includes provisions indicating that the exiting participants would remain obligated for their proportionate shares of environmental, mine reclamation, and certain other legacy liabilities that are attributable to activities that occurred prior to their exit, as well as outlining how their shares would be determined. Also, on June 26, 2014, a non-binding term sheet was approved by all of the remaining participants that provides the essential terms of restructured ownership of SJGS among the remaining participants. As part of the non-binding terms, PNM confirmed that it would acquire an additional 132 MW in SJGS Unit 4 effective December 31, 2017. There would be no initial cost for PNM to acquire the additional 132 MW although PNM’s share of capital improvements, including the costs of installing SNCR and BDT equipment, and operating expenses would increase to reflect the increased ownership percentage. The acquisition of 132 MW of SJGS Unit 4 would result in PNM’s ownership share of SJGS Unit 4 being 64.5% and of SJGS Units 1 and 4 aggregating 58.7% . On September 2, 2014,

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the SJGS Coordination Committee adopted a non-binding supplement to the Resolution, which provides for allocation of future costs of decommissioning among current SJGS owners using a time-based sliding scale and outlines indemnification obligations. The Resolution and the non-binding term sheet recognize that prior to executing a binding restructuring agreement, the remaining participants would need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. As discussed under Coal Supply below, on July 1, 2015, PNM entered into an agreement for the supply of coal to SJGS through June 30, 2022.

In September 2014, the SJGS participants executed a binding Fuel and Capital Funding Agreement to implement certain provisions of the Resolution, including payment by the remaining participants of capital costs for the Unit 4 SNCR project starting July 1, 2014, and acquisition by PNM of the exiting participants’ coal inventory as of January 1, 2015. PNM filed the Fuel and Capital Funding Agreement with FERC on September 18, 2014, with a request for a retroactive effective date to July 1, 2014. FERC approved the request on November 13, 2014.

On January 7, 2015, the City of Farmington, New Mexico, which has an ownership interest in SJGS Unit 4, notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs in that unit unsubscribed. The City of Farmington’s action was taken under the Fuel and Capital Funding Agreement and has the impact of negating certain provisions of that agreement, including the payment arrangement related to SNCRs and PNM’s acquisition of the exiting participants’ coal inventory described above, and reinstating the voting and capital improvement cost allocations under the current SJPPA. Accordingly, on February 3, 2015, PNM informed the participants in the Fuel and Capital Funding Agreement that the agreement would terminate by its terms no later than February 6, 2015. The City of Farmington and the other continuing participants in SJGS have indicated that they remain committed to on-going ownership in SJGS.

On May 19, 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into the COFA, which provides PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those of PNMR Development for the 65 MW. PNMR guarantees the obligations of PNMR Development under the COFA. The COFA will terminate on the earliest of the effective date of a SJGS restructuring agreement, the date PNM notifies the other parties that it has failed to receive required regulatory approvals for the SJGS restructuring, the date any California owner opposes PNM’s application before the NMPRC, or the date PNM elects to terminate because another SJGS owner has given notice that it will no longer participate in the restructuring process. If the COFA is terminated, the California owners would not be obligated to repay amounts funded by PNM and PNMR Development. On June 23, 2015, ABCWUA filed a motion with the NMPRC to void the COFA alleging that the COFA violated the NMPRC’s rules regarding affiliate transactions. As discussed under NMPRC Filing above, ABCWUA subsequently withdrew its pending motion to void the COFA, but NEE later filed a separate motion to void the COFA together with a filing opposing the Stipulated Settlement.

On May 1, 2015, PNM filed with the NMPRC a notice of submittal of a confidential, substantially final, unexecuted copy of the San Juan Project Restructuring Agreement (“RA”). The RA sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the Resolution. PNMR Development would also be a party to the RA and would acquire an ownership interest in SJGS Unit 4 when the California owners exit, but would have obligations related to Unit 4 before then. On the exit date, which is anticipated to be December 31, 2017, PNM and PNMR Development would acquire 132 MW and 65 MW of the capacity in SJGS Unit 4 from the California owners, as contemplated by the COFA. As discussed under NMPRC Filing above, the Stipulated Settlement would allow PNM to acquire the 65 MW, which the RA anticipates will be acquired by PNMR Development. PNMR currently anticipates that, if all necessary approvals are received and the RA becomes effective, PNMR Development would transfer the rights and obligations related to the 65 MW to PNM prior to December 31, 2017 in order to facilitate dispatch of power from that capacity.

The RA is dependent on and would become effective upon the last of the approval of the underlying transactions by NMPRC and FERC and the effective date of a new coal supply agreement (“CSA”) for SJGS. The effectiveness of the new CSA is dependent on the closing of the purchase of the existing coal mine operation by a new mine operator, as discussed in Coal Supply below. The agreement for the purchase of the mine operation will terminate if its closing has not occurred by June 30, 2016. It is currently anticipated that the new CSA and the RA would become effective contemporaneously on January 1, 2016. The RA sets forth the terms under which PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal

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supply to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits that will be passed on to PNM’s customers. The RA also includes provisions whereby the exiting owners will make payments to certain of the remaining participants, not including PNM, related to the restructuring. PNM’s May 1, 2015 notice also included submittal of confidential, substantially final, unexecuted copies of documents related to coal supply for SJGS beginning January 1, 2016 (see “Coal Supply” below). On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015, which was subsequently extended to August 1, 2015. On July 1, 2015, PNM filed with the NMPRC fully executed coal supply and related agreements along with a partially executed RA, an agreement covering decommissioning obligations and funding for the SJGS plant, and related amendments to the SJPPA. PNM filed the fully executed RA and related agreements along with supporting testimony on July 31, 2015.

On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation of the restructured SJGS participation agreements and is planning on supplementing its application in November 2015. FERC has established November 24, 2015 as the deadline for responses to PNM’s application. PNM requested that FERC rule on its application by December 31, 2015.

PNM is unable to predict whether all required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring to be consummated. If timely regulatory approvals required for the RA and new CSA to become effective on January 1, 2016 are not obtained, payments from the exiting participants would be delayed. In addition, PNM and its customers would not receive the full benefits of the new coal arrangements under the RA and new CSA. A significant delay could impact the viability of the RA and could require renegotiation of the restructuring, which could result in terms and conditions that are substantially different than the arrangements under the RA.

Other SJGS Matters – The SJPPA requires PNM, as operating agent, to obtain approval of capital improvement project expenditures from participants who have an ownership interest in the relevant unit or property common to more than one unit. As provided in the SJPPA, specified percentages of both the outstanding participant shares, based on MW ownership, and the number of participants in the unit or common property must be obtained in order for a capital improvement project to be approved. PNM presented the SNCR project, including BDT requirements described above, to the SJGS participants in Unit 1 and Unit 4 for approval in October 2013. The project was approved for Unit 1, but the Unit 4 project, which includes some of the California participants, did not obtain the required percentage of votes for approval. PNM subsequently submitted several requests that the owners of Unit 4 approve certain expenditures critical to comply with the time frame in the RSIP, as well as requests to approve the total forecasted project expenses. The required majority of Unit 4 owners did not approve these requests.

PNM, in its capacity as operating agent of SJGS, is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending the resolution, by arbitration or otherwise, of any inability or failure to agree by the participants. PNM must evaluate its responsibilities and obligations as operating agent under the SJPPA regarding the SJGS Unit 4 capital projects that were not approved by the participants and take reasonable and prudent actions as it deems necessary. Therefore, PNM, as operating agent for SJGS, issued several “Prudent Utility Practice” notices under the SJPPA indicating PNM was undertaking certain critical activities to keep the Unit 4 SNCR project on schedule.

As discussed above, EPA approved the RSIP and withdrew the FIP on October 9, 2014 and those approvals became effective on November 10, 2014. PNM believes significant progress is being made towards implementation of the RSIP. However, the final implementation of the RSIP is still dependent upon PNM obtaining NMPRC approval to retire SJGS Units 2 and 3 and the agreements for restructuring and a new coal supply becoming effective. PNM can provide no assurance that these requirements will be accomplished. If the RSIP requirements ultimately are not implemented due to adverse or alternative regulatory, legislative, legal, or restructuring developments or other factors, PNM would need to pursue other alternatives to address compliance with the CAA. Failure to implement the RSIP or an agreed to alternative could jeopardize the economic viability of SJGS. PNM will seek recovery from its ratepayers for costs that may be incurred as a result of the CAA requirements. PNM is unable to predict the ultimate outcome of these matters.

Although the additional equipment and other final requirements will result in additional capital and operating costs being incurred, PNM believes that its access to the capital markets is sufficient to be able to finance its share of the installation. It is possible that requirements to comply with the CAA, combined with the financial impact of possible future climate change regulation

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or legislation, if any, other environmental regulations, the result of litigation, and other business considerations, could jeopardize the economic viability of SJGS or the ability or willingness of individual participants to continue participation in the plant.

Four Corners

On August 6, 2012, EPA issued its Four Corners FIP with a final BART determination for Four Corners. The rule included two compliance alternatives. On December 30, 2013, APS notified EPA that the Four Corners participants selected the alternative that required APS to permanently close Units 1-3 by January 1, 2014 and install SCR post-combustion NOx controls on each of Units 4 and 5 by July 31, 2018. PNM owns a 13% interest in Units 4 and 5, but had no ownership interest in Units 1, 2, and 3, which were shut down by APS on December 30, 2013. For particulate matter emissions, EPA is requiring Units 4 and 5 to meet an emission limit of 0.015 lb/MMBTU and the plant to meet a 20% opacity limit, both of which are achievable through operation of the existing baghouses. Although unrelated to BART, the final BART rule also imposes a 20% opacity limitation on certain fugitive dust emissions from Four Corners’ coal and material handling operations.

On December 30, 2013, APS announced the closing of its purchase of SCE’s 48% interest in each of Units 4 and 5 of Four Corners. Concurrently with the closing of the SCE transaction, the ownership of the coal supplier and operator of the mine that serves Four Corners was transferred to a company formed by the Navajo Nation to own the mine and develop other energy projects. Also occurring concurrently, the Four Corners co-owners executed a long-term agreement for the supply of coal to Four Corners from July 2016, when the current coal supply agreement expires, through July 2031.

APS, on behalf of the Four Corners participants, negotiated amendments to an existing facility lease with the Navajo Nation, which extends the Four Corners leasehold interest from 2016 to 2041. The Navajo Nation approved these amendments in March 2011. The effectiveness of the amendments also required the approval of the DOI, as did a related federal rights-of-way grant that culminated in the issuance of a DOI Record of Decision on July 17, 2015. The Record of Decision approves the 25 -year site lease extension with the Navajo Nation for Four Corners, authorizes continued mining operations to supply the remaining units at Four Corners, renews transmission line and access road rights-of-way on the Navajo and Hopi Reservations, and accepts the proposed mining plan for the Navajo Mine. The record of decision provides the authority for the Bureau of Indian Affairs to sign the lease amendments and rights-of-way renewals, which occurred in late July 2015. In addition, installation of SCR control technology at Four Corners requires a PSD permit, which APS received in December 2014.

The Four Corners participants’ obligations to comply with EPA’s final BART determinations, coupled with the financial impact of possible future climate change regulation or legislation, other environmental regulations, and other business considerations, could jeopardize the economic viability of Four Corners or the ability of individual participants to continue their participation in Four Corners.

PNM is continuing to evaluate the impacts of EPA’s BART determination for Four Corners. PNM estimates its share of costs, including PNM’s AFUDC, to be up to $91.4 million for post-combustion controls at Four Corners Units 4 and 5. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM is unable to predict the ultimate outcome of this matter.

Carbon Dioxide Emissions

On August 3, 2015, EPA established final standards to limit CO ₂ emissions from power plants. EPA took three separate but related actions in which it: (1) established the final carbon pollution standards for new, modified and reconstructed power plants; (2) established the final Clean Power Plan to set standards for carbon emission reductions from existing power plants; and (3) released a proposed federal plan associated with the final Clean Power Plan. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups subsequently filed petitions for review and motions to stay in the D.C. Circuit.

The Clean Power Plan establishes state-by-state targets for carbon emissions reduction and requires states to submit initial plans to EPA by September 6, 2016. EPA may grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension must submit an update to EPA in 2017. All final state plans must be submitted to EPA by 2018. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. State measures plans may only be used with mass-

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based goals and must include “backstop” federally enforceable standards that will become effective if the state measures fail to achieve the expected level of emission reductions. Because Four Corners is located on Navajo Nation land, the Four Corners FIP, discussed above, will determine how the final Clean Power Plan regulations will affect that plant. APS continues to advocate for Clean Power Plan compliance options that provide maximum operational flexibility. APS will continue to monitor these standards as they are implemented. PNM is currently reviewing the new CO ₂ emission reductions standards, but cannot predict the impact they may have on its operations or a range of the potential costs of compliance.

National Ambient Air Quality Standards (“NAAQS”)

The CAA requires EPA to set NAAQS for pollutants considered harmful to public health and the environment. EPA has set NAAQS for certain pollutants, including NOx, SO ₂ , ozone, and particulate matter. In 2010, EPA updated the primary NOx and SO ₂ NAAQS to include a 1-hour maximum standard while retaining the annual standards for NOx and SO ₂ and the 24-hour SO ₂ standard. New Mexico is in attainment for the 1-hour NOx NAAQS. On May 13, 2014, EPA released the draft data requirements rule for the 1-hour SO ₂ NAAQS, which directs state and tribal air agencies to characterize current air quality in areas with large SO ₂ sources to identify maximum 1-hour SO ₂ concentrations. The proposed rule also describes the process and timetable by which air regulatory agencies would characterize air quality around large SO ₂ sources through ambient monitoring or modeling. This characterization will result in these areas being designated as attainment, nonattainment, or unclassified for compliance with the 1-hour SO ₂ NAAQS. On March 2, 2015, the United States District Court for the Northern District of California approved a settlement that imposes deadlines for EPA to identify areas that violate the NAAQS standards for 1-hour SO ₂ emissions. The settlement results from a lawsuit brought by Earthjustice on behalf of the Sierra Club and the Natural Resources Defense Council under the CAA. The consent decree requires the following: 1) within 16 months of the consent decree entry, EPA must issue area designations for areas containing non-retiring facilities that either emitted more than 16,000 tons of SO ₂ in 2012 or emitted more than 2,600 tons with an emission rate of 0.45 lbs/MMBTU or higher in 2012; 2) by December 2017, EPA must issue designations for areas for which states have not adopted a new monitoring network under the proposed data requirements rule; and (3) by December 2020, EPA must issue designations for areas for which states have adopted a new monitoring network under the proposed data requirements rule. SJGS and Four Corners SO ₂ emissions are below the tonnages set forth in 1) above. EPA regions sent letters to state environmental agencies explaining how EPA plans to implement the consent decree. The letters outline the schedule that EPA expects states to follow in moving forward with new SO ₂ non-attainment designations. NMED did not receive a letter.

On August 11, 2015, EPA released the Data Requirements Rule for SO ₂ , telling states how to model or monitor to determine attainment or nonattainment with the new 1-hour SO ₂ NAAQS. If NMED chooses the modeling approach that EPA encourages states to adopt, the NMED must submit a modeling protocol for SJGS to EPA by July 1, 2016. NMED must then submit modeling results for SJGS to EPA by January 13, 2017. However, if NMED chooses the monitoring approach, a more relaxed schedule would apply. If SJGS can accept a federally enforceable 2,000 tons per year source-wide limit before January 13, 2017, modeling would not be required by EPA. PNM is currently evaluating the rule to understand its impacts.

PNM believes that compliance with the 1-hour SO ₂ standard may require operational changes and/or equipment modifications at SJGS. On November 8, 2013, PNM received an amendment to its NSR air permit for SJGS, which would be required for the installation of either SCRs or SNCRs described above. The revised permit requires the reduction of SO ₂ emissions to 0.10 pound per MMBTU on SJGS Units 1 and 4 and continues to require the installation of BDT equipment modifications for the purpose of reducing fugitive emissions, including NOx, SO ₂ , and particulate matter. These reductions will help SJGS meet the NAAQS. The BDT equipment modifications are to be installed at the same time as the installation of regional haze BART controls, in order to most efficiently and cost effectively conduct construction activities at SJGS. See Regional Haze – SJGS above.

EPA finalized revisions to its NAAQS for fine particulate matter on December 14, 2012. PNM believes the equipment modifications discussed above will assist the plant in complying with the particulate matter NAAQS.

In January 2010, EPA announced it would strengthen the 8-hour ozone standard by setting a new standard in a range of 60 - 70 parts per billion (“ppb”). On December 17, 2014, EPA published a proposed rule to revise the NAAQS for ground level ozone. The rule would reduce the current primary 8-hour ozone NAAQS from 75 ppb to between 70 and 65 ppb. EPA proposed a secondary standard to provide protection against cumulative exposures that can damage plants and trees. To achieve this level of protection, EPA proposed an 8-hour secondary standard at a level within the range of 65 to 70 ppb. On October 1, 2015, EPA

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finalized the new ozone NAAQS and lowered both the primary and secondary 8-hour standard from 75 ppb to 70 ppb. With ozone standards becoming more stringent, fossil-fueled generation units will come under increasing pressure to reduce emissions of nitrogen oxides and volatile organic compounds, and to generate emission offsets for new projects or facility expansions located in nonattainment areas. EPA plans to propose rules and guidance over the next year to help states with potential nonattainment areas implement the revised standards. EPA also plans to update its Exceptional Events Rule, which outlines the requirements for excluding air quality data (including ozone data) from regulatory decisions if the data are affected by events outside an area’s control.

As required by the CAA, EPA anticipates making attainment/nonattainment designations for the revised standards by late 2017. Those designations likely will be based on 2014-2016 air quality data. Counties that exceed the ozone NAAQS would be designated as nonattainment for ozone. NMED would have responsibility for bringing those counties into compliance and would look at all sources of NOx and volatile organic compounds since these are the pollutants that form ground-level ozone.

Should San Juan County become non-attainment for ozone, SJGS could be required to install further controls to meet the new ozone NAAQS. Until EPA approves attainment designations for the Navajo Nation and releases a proposal to implement the revised ozone NAAQS, APS is unable to predict what impact the adoption of these standards may have on Four Corners. PNM cannot predict the outcome of this matter, the impact of other potential environmental mitigations, or if additional controls would be required at any of its affected facilities as a result of ozone non-attainment designation.

Citizen Suit Under the Clean Air Act

The operations of SJGS are covered by a Consent Decree with the Grand Canyon Trust and Sierra Club and with the NMED that includes stipulated penalties for non-compliance with specified emissions limits. Stipulated penalty amounts are placed in escrow on a quarterly basis pending review of SJGS’s emissions performance. In May 2011, PNM entered into an agreement with NMED and the plaintiffs to resolve a dispute over the applicable NOx emission limits under the Consent Decree. Under the agreement, so long as the NOx emissions limits imposed under the EPA FIP and the New Mexico SIP meet a specified emissions limit, and PNM does not challenge these limits, the parties’ dispute is deemed settled.

In May 2010, PNM filed a petition with the federal district court seeking a judicial determination on a dispute relating to PNM’s mercury controls. NMED and plaintiffs sought to require PNM to implement additional mercury controls. PNM estimated the implementation would increase annual mercury control costs for the entire station from $0.7 million to $6.6 million . On March 23, 2014, the court entered a stipulated order reflecting an agreement reached by the parties. Under the stipulated order, PNM was required to repeat the mercury study required under the Consent Decree using sorbent traps instead of the continuous emissions monitoring system used in the initial study. The results of the mercury study would establish the activated carbon injection rate that maximizes mercury removal at SJGS, as required under the Consent Decree. PNM completed stack testing and submitted the study report to NMED and the plaintiffs in December 2014. Based on PNM’s cost/benefit analysis, PNM recommended that the carbon injection not be increased from its current level. On March 18, 2015, NMED and the plaintiffs approved PNM’s recommendation for the activated carbon injection rate. The NSR permit issued by NMED on May 14, 2015 incorporates this operational parameter as a permit condition.

Four Corners Clean Air Act Lawsuit

In October 2011, Earthjustice, on behalf of several environmental organizations, filed a lawsuit in the United States District Court for the District of New Mexico against APS and the other Four Corners participants alleging violations of the NSR provisions of the CAA and NSPS violations. The parties agreed on terms of a settlement. On June 24, 2015, the United States Department of Justice (“DOJ”) lodged the executed consent decree with the United States District Court for the District of New Mexico and published notice of the filing in the Federal Register. On August 17, 2015, the consent decree was entered by the court, marking resolution to the litigation. The settlement resolves claims by the government and environmental plaintiffs that the co-owners violated the CAA by modifying Four Corners Units 4 and 5 without first obtaining a pre-construction permit from EPA. The settlement requires installation of pollution control technology and implementation of other measures to reduce SO ₂ and NOx emissions from the two units, although installation of much of this equipment was already planned in order to comply with EPA's Regional Haze Rule BART requirements. The settlement also requires Four Corners co-owners to pay a civil penalty of $1.5 million and spend $6.2 million for certain environmental mitigation projects to benefit the Navajo Nation. PNM is responsible

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for 13% of these costs based on its ownership interest in the units at the time of the alleged violations, which PNM recorded in 2014.

Four Corners Coal Mine

In 2012, several environmental groups filed a lawsuit in federal district court against the OSM challenging OSM’s 2012 approval of a permit revision which allowed for the expansion of mining operations into a new area of the mine that serves Four Corners (“Area IV North”). In April 2015, the court issued an order invalidating the permit revision, thereby prohibiting mining in Area IV North until OSM takes action to cure the defect in its permitting process identified by the court. APS has indicated that the owner of the mine does not anticipate any near-term interruption of coal supply to the plant as a result of the suspension of mining in Area IV North. PNM cannot predict the time period that will be required for OSM’s further permitting process to be completed or whether the outcome of the process will be sufficient to allow the permit to be reinstated.

WEG v. OSM NEPA Lawsuit

In February 2013, WEG filed a Petition for Review in the United States District Court of Colorado against OSM challenging federal administrative decisions affecting seven different mines in four states issued at various times from 2007 through 2012. In its petition, WEG challenges several unrelated mining plan modification approvals, which were each separately approved by OSM. Of the fifteen claims for relief in the WEG Petition, two concern SJCC’s San Juan mine. WEG’s allegations concerning the San Juan mine arise from OSM administrative actions in 2008. WEG alleges various NEPA violations against OSM, including, but not limited to, OSM’s alleged failure to provide requisite public notice and participation, alleged failure to analyze certain environmental impacts, and alleged reliance on outdated and insufficient documents. WEG’s petition seeks various forms of relief, including a finding that the federal defendants violated NEPA by approving the mine plans; voiding, reversing, and remanding the various mining modification approvals; enjoining the federal defendants from re-issuing the mining plan approvals for the mines until compliance with NEPA has been demonstrated; and enjoining operations at the seven mines. SJCC intervened in this matter. The court granted SJCC’s motion to sever its claims from the lawsuit and transfer venue to the United States District Court for the District of New Mexico. Legal briefing is complete. A stay in this matter has expired although the parties continue to engage in settlement negotiations. If WEG ultimately obtains the relief it has requested, such a ruling could require significant expenditures to reconfigure operations at the San Juan mine, impact the production of coal, and impact the economic viability of the San Juan mine and SJGS. PNM cannot currently predict the outcome of this matter or the range of its potential impact.

Navajo Nation Environmental Issues

Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government, as well as a lease from the Navajo Nation. The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those activities that occur at Four Corners. In October 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation challenging the applicability of the Navajo Acts to Four Corners. In May 2005, APS and the Navajo Nation signed an agreement resolving the dispute regarding the Navajo Nation’s authority to adopt operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. As a result of this agreement, APS sought, and the courts granted, dismissal of the pending litigation in the Navajo Nation Supreme Court and the Navajo Nation District Court, to the extent the claims relate to the CAA. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts. PNM cannot currently predict the outcome of these matters or the range of their potential impacts.

Cooling Water Intake Structures

EPA signed its final cooling water intake structures rule on May 16, 2014, which establishes national standards for certain cooling water intake structures at existing power plants and other facilities under the Clean Water Act to protect fish and other aquatic organisms by minimizing impingement mortality (the capture of aquatic wildlife on intake structures or against screens) and entrainment mortality (the capture of fish or shellfish in water flow entering and passing through intake structures). The final rule was published on August 15, 2014 and became effective October 14, 2014.

The final rule allows multiple compliance options and considerations for site specific conditions and the permit writer is granted a significant amount of discretion in determining permit requirements, schedules, and conditions. To minimize impingement

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mortality, the rule provides operators of facilities, such as SJGS and Four Corners, seven options for meeting Best Technology Available (“BTA”) standards for reducing impingement. SJGS has a closed-cycle recirculating cooling system, which is a listed BTA and may also qualify for the “de minimis rate of impingement” based on the design of the intake structure. To minimize entrainment mortality, the permitting authority must establish the BTA for entrainment on a site-specific basis, taking into consideration an array of factors, including endangered species and social costs and benefits. Affected sources must submit source water baseline characterization data to the permitting authority to assist in the determination. Compliance deadlines under the rule are tied to permit renewal and will be subject to a schedule of compliance established by the permitting authority.

On August 27, 2015, PNM submitted a request to EPA to terminate the SJGS National Pollutant Discharge Elimination System (“NPDES”) permit. Although SJGS has been a zero discharge facility for several years, EPA had required the plant to maintain a NPDES permit. On September 22, 2015, EPA issued a letter approving the termination request. The cooling water intake structure rule still applies to SJGS as the plant operates under the EPA NPDES Multi-Sector General Stormwater Permit (“MSGP”). On June 4, 2015, the EPA reissued and revised the MSGP. PNM does not expect material changes as a result of any requirements that may be imposed upon SJGS related to cooling water intake structures.

APS is currently in discussions with EPA Region 9, the NPDES permit writer for Four Corners, to determine the scope of the impingement and entrainment requirements, which will, in turn, determine APS’s costs to comply with the rule. APS has indicated that it does not expect such costs to be material.

Effluent Limitation Guidelines

On June 7, 2013, EPA published proposed revised wastewater effluent limitation guidelines establishing technology-based wastewater discharge limitations for fossil fuel-fired electric power plants. EPA’s proposal offers numerous options that target metals and other pollutants in wastewater streams originating from fly ash and bottom ash handling activities, scrubber activities, and non-chemical metal cleaning waste operations. The preferred alternatives differ with respect to the scope of requirements that would be applicable to existing discharges of pollutants found in wastestreams generated at existing power plants. All four alternatives would establish a “zero discharge” effluent limit for all pollutants in fly ash transport water. However, requirements governing bottom ash transport water differ depending on which alternative EPA ultimately chooses and could range from effluent limits based on Best Available Technology Economically Achievable to “zero discharge” effluent limits.

EPA signed the final Steam Electric Effluent Guidelines Rule on September 30, 2015 and released the pre-publication copy. The final rule phases in the new, more stringent requirements in the form of effluent limits for arsenic, mercury, selenium, and nitrogen for wastewater discharged from wet scrubber systems and zero discharge of pollutants in ash transport water that must be incorporated into plants’ NPDES permits. Each plant must comply between 2018 and 2023 depending on when it needs a new/revised NPDES permit.

Because SJGS is zero discharge for wastewater and no longer holds an NPDES permit, it is expected that minimum to no requirements will be imposed. Reeves Station, a PNM-owned gas-fired generating station, discharges cooling tower blowdown to a publicly owned treatment works and holds an NPDES permit. Applicability of the rule will need to be assessed. It is expected that minimum to no requirements will be imposed at Reeves.

Based upon the requirements of the final Steam Electric Effluent Guidelines Rule, Four Corners may be required to change equipment and operating practices affecting boilers and ash handling systems, as well as change its waste disposal techniques. Until a draft NPDES permit is proposed for Four Corners, APS is uncertain what will be required to comply with the finalized effluent limitations. However, APS has indicated it believes that compliance costs at Four Corners will be immaterial. PNM is unable to predict the outcome of this matter or a range of the potential costs of compliance.

Santa Fe Generating Station

PNM and the NMED are parties to agreements under which PNM installed a remediation system to treat water from a City of Santa Fe municipal supply well, an extraction well, and monitoring wells to address gasoline contamination in the groundwater at the site of PNM’s former Santa Fe Generating Station and service center. PNM believes the observed groundwater contamination originated from off-site sources, but agreed to operate the remediation facilities until the groundwater meets applicable federal and state standards or until the NMED determines that additional remediation is not required, whichever is earlier. The City of

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Santa Fe has indicated that since the City no longer needs the water from the well, the City would prefer to discontinue its operation and maintain it only as a backup water source. However, for PNM’s groundwater remediation system to operate, the water well must be in service. Currently, PNM is not able to assess the duration of this project or estimate the impact on its obligations if the City of Santa Fe ceases to operate the water well.

The Superfund Oversight Section of the NMED has conducted multiple investigations into the chlorinated solvent plume in the vicinity of the site of the former Santa Fe Generating Station. In February 2008, a NMED site inspection report was submitted to EPA, which states that neither the source nor extent of contamination has been determined and that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. In January 2013, NMED notified PNM that monitoring results from April 2012 showed elevated concentrations of nitrate in three monitoring wells and an increase in free-phase hydrocarbons in another well. None of these wells are routinely monitored as part of PNM’s obligations under the settlement agreement. In April 2013, NMED conducted the same level of testing on the wells as was conducted in April 2012, which produced similar results. PNM conducted similar site-wide sampling activities in April 2014 and obtained results similar to the 2013 data. As part of this effort, PNM also collected a sample of hydrocarbon product for “fingerprint” analysis from a monitoring well located on the northeastern corner of the property. This analysis indicated that the hydrocarbon product was a mixture of newer and older fuels, and the location of the monitoring well suggests that the hydrocarbon product is likely from offsite sources. PNM does not believe the former generating station is the source of the increased levels of free-phase hydrocarbons, but no conclusive determinations have been made. It is possible that PNM’s prior activities to remediate hydrocarbon contamination, as conducted under an NMED-approved plan, may have resulted in increased nitrate levels. Additional testing and analysis will need to be performed before conclusions can be reached regarding the cause of the increased nitrate levels or the method and cost of remediation. PNM is unable to predict the outcome of these matters.

Coal Combustion Byproducts Waste Disposal

CCBs consisting of fly ash, bottom ash, and gypsum from SJGS are currently disposed of in the surface mine pits adjacent to the plant. SJGS does not operate any CCB impoundments. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash with federal oversight by the OSM. APS disposes of CCBs in ash ponds and dry storage areas at Four Corners. Ash management at Four Corners is regulated by EPA and the New Mexico State Engineer’s Office.

In June 2010, EPA published a proposed rule that included two options for waste designation of coal ash. One option was to regulate CCBs as a hazardous waste, which would allow EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option was to regulate CCBs as a non-hazardous waste, which would provide EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily by state authorities or through citizen suits. Both options allow for continued use of CCBs in beneficial applications.

On January 29, 2014, in a consolidated case in the D.C. Circuit involving several environmental groups, including Sierra Club, and industry group members, the court issued a consent decree directing EPA to publish its final action regarding whether or not to pursue the proposed non-hazardous waste option for CCBs by December 19, 2014.

On December 19, 2014, EPA issued its coal ash rule, including a non-hazardous waste determination for coal ash. Coal ash will be regulated as a solid waste under Subtitle D of RCRA. The rule sets minimum criteria for existing and new CCB landfills and existing and new CCB surface impoundments and all lateral expansions consisting of location restrictions, design and operating criteria, groundwater monitoring and corrective action, closure requirements and post closure care, and recordkeeping, notification, and internet posting requirements.

The rule does not cover mine placement of coal ash and OSM is expected to publish a rule covering mine placement in 2015. It is expected that OSM will be influenced by EPA’s rule. Because the rule is promulgated under Subtitle D, it does not require regulated facilities to obtain permits, does not require the states to adopt and implement the new rules, and is not within EPA’s enforcement jurisdiction. Instead, the rule’s compliance mechanism is for a state or citizen group to bring a RCRA citizen suit in federal district court against any facility that is alleged to be in non-compliance with the new requirements. EPA published the final CCB rule in the Federal Register on April 17, 2015. Based upon the requirements of the final rule, PNM conducted a CCB assessment at SJGS and will make minor modifications at the plant to ensure that there are no facilities which would be

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considered impoundments under the rule. PNM does not expect it to have a material impact on PNM’s operations, financial position, or cash flows.

The rule’s preamble indicates EPA is still evaluating whether to reverse its original regulatory determination and regulate coal ash under RCRA Subtitle C, which means it is possible at some point in the future for EPA to review the new CCB rules. PNM would seek recovery from its ratepayers of all costs that are ultimately incurred. PNM cannot predict the outcome of OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether OSM’s actions will have a material impact on PNM’s operations, financial position, or cash flows.

Hazardous Air Pollutants (“HAPs”) Rulemaking

In December 2011, the EPA issued its final Mercury and Air Toxics Standards (“MATS”) to reduce emissions of heavy metals, including mercury, arsenic, chromium, and nickel, as well as acid gases, including hydrochloric and hydrofluoric gases, from coal and oil-fired electric generating units with a capacity of at least 25 MW. Existing facilities were required to comply with the MATS rule by April 16, 2015, unless the facility was granted a 1-year extension under CAA section 112(i)(3). PNM has control technology on each of the four units at SJGS that provides 99% mercury removal efficiency. The plant is in compliance with the MATS. Therefore, PNM did not request an extension and began complying with the MATS rule by the date specified in the rule. APS has determined that no additional equipment will be required at Four Corners Units 4 and 5 to comply with the rule.

On June 29, 2015, the United States Supreme Court issued its decision overturning the MATS rule. The justices ruled that EPA should have taken costs to utilities and others in the power sector into consideration before issuing the MATS rule. The case is now remanded to the D.C. Circuit for further proceedings consistent with the opinion. No changes are required at SJGS as a result of the Supreme Court action.

Other Commitments and Contingencies

Coal Supply

SJGS

The coal requirements for SJGS are currently being supplied by SJCC, a wholly owned subsidiary of BHP. In addition to coal delivered to meet the current needs of SJGS, PNM prepays SJCC for certain coal mined but not yet delivered to the plant site. At September 30, 2015 and December 31, 2014, prepayments for coal, which are included in other current assets, amounted to $44.9 million and $37.3 million . SJCC holds certain federal, state, and private coal leases and has an underground coal sales agreement (“UG-CSA”) to supply processed coal for operation of SJGS through 2017. The parties to the UG-CSA are SJCC, PNM, and Tucson. Under the UG-CSA, SJCC is reimbursed for all costs for mining and delivering the coal, including an allocated portion of administrative costs, and receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the UG-CSA. The UG-CSA contemplates the delivery of coal that would supply substantially all the requirements of SJGS through December 31, 2017.

In conjunction with the activities undertaken to comply with the CAA for SJGS, as discussed above, PNM and the other owners of SJGS evaluated alternatives for the supply of coal to SJGS after the expiration of the current coal sales agreement. As discussed under SJGS Ownership Restructuring Matters above, the Resolution and the non-binding term sheet approved by the SJGS Coordination Committee on June 26, 2014 recognized that prior to executing a binding restructuring agreement relating to the ownership of SJGS, the remaining participants would need to have greater certainty in regard to the cost and availability of fuel for SJGS for the period after December 31, 2017. The remaining participants began the process of negotiating agreements concerning future fuel supply for SJGS. On October 1, 2014, the San Juan Fuels Committee approved a resolution authorizing an amendment to the UG-CSA. The amendment provided for the negotiation of a potential purchase transaction for the mine assets by one or more of the utilities, an affiliate, or another entity agreed to by the parties to be consummated on or before December 31, 2016. The amendment, which was effective as of October 2, 2014, also released the parties from the obligation to negotiate an extension of the UG-CSA, but does not impact the utilities’ option to purchase the mining assets at the end of the current contract term if the purchase transaction is not completed.

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Following extensive negotiations among the SJGS participants, the owner of SJCC, and third-party miners, substantially final, unexecuted forms of agreements were negotiated under which the ownership of SJCC would transfer to a new third-party miner and PNM would enter into a new coal supply agreement (“CSA”) and agreements for CCB disposal and mine reclamation services with SJCC on or about January 1, 2016. On May 1, 2015, PNM filed a notice of submittal of confidential, substantially final, unexecuted copies of the CSA, the mine reclamation agreement, and the CCB disposal agreement with the NMPRC. Effectiveness of the agreements would be dependent upon the closing of the purchase of SJCC by the new third-party miner and the finalization of the RA and other agreements, which along with regulatory approvals are necessary for the restructuring of ownership in SJGS to be consummated. On May 14, 2015, PNM and Westmoreland Coal Company (“Westmoreland”) entered into a letter agreement whereby each party agreed to enter into and deliver the CSA, the mine reclamation agreement, and the CCB disposal agreement on terms substantially in the form submitted to the NMPRC on May 1, 2015.

The NMPRC issued an order on May 27, 2015 requiring that PNM file executed agreements related to coal supply by July 1, 2015. On July 1, 2015, PNM and Westmoreland entered into the CSA, pursuant to which Westmoreland would supply all of the coal requirements of SJGS through June 30, 2022, under substantially the same terms as were contemplated by the unexecuted CSA with SJCC filed with the NMPRC on May 1, 2015. PNM and Westmoreland also entered into agreements under which Westmoreland will provide CCB disposal and mine reclamation services. Contemporaneous with the entry into the coal-related agreements, Westmoreland entered into a stock purchase agreement on July 1, 2015, which provides that Westmoreland will acquire all of the capital stock of SJCC. Upon closing under the stock purchase agreement, Westmoreland’s rights and obligations under the CSA and the agreements for CCB disposal and mine reclamation services will be assigned to SJCC. PNM and Westmoreland also entered into an agreement to terminate the May 14, 2015 letter agreement. In addition, PNM, Tucson, SJCC, and SJCC’s owner entered into an agreement to terminate the existing UG-CSA upon the effective date of the new CSA. The CSA and related agreements will become effective upon the closing of that stock purchase agreement and the effectiveness of the RA. The stock purchase agreement will terminate on June 30, 2016 if its closing has not occurred. If the CSA does not become effective, the UG-CSA would remain in effect through its contractual expiration on December 31, 2017. The CSA and related agreements were filed with the NMPRC on July 1, 2015.

Pricing under the CSA would primarily be fixed, adjusted to reflect general inflation. The pricing structure takes into account that SJCC has been paid for coal mined but not delivered, as discussed above. PNM would have the option to extend the CSA, subject to negotiation of the term of the extension and compensation to the miner. The RA sets forth terms under which PNM will supply coal to the SJGS exiting participants for the period from January 1, 2016 through December 31, 2017 and to the SJGS remaining participants over the term of the CSA. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement with SJCC. Since substantially all of PNM’s coal costs are passed through the FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners, which is discussed above, would be passed through to PNM’s customers.

It is currently anticipated that the CSA and the RA would become effective contemporaneously on January 1, 2016. PNM cannot predict if all of the necessary requirements will be satisfied and all approvals obtained in order for these agreements to become effective on that date.

Four Corners

APS purchased all of Four Corners’ coal requirements from a supplier that was also a subsidiary of BHP and had a long-term lease of coal reserves with the Navajo Nation. That contract was to expire on July 6, 2016 with pricing determined using an escalating base-price. On December 30, 2013, ownership of the mine was transferred to an entity owned by the Navajo Nation and a new coal supply contract for Four Corners, beginning in July 2016 and expiring in 2031, was entered into with that entity. The BHP subsidiary is to be retained as the mine manager and operator until December 2016. Coal costs are anticipated to increase approximately 30% at the inception of the new contract. The contract provides for pricing adjustments over its term based on economic indices. PNM anticipates that its share of the increased costs will be recovered through its FPPAC.

Coal Mine Reclamation

In 2013, PNM updated its study of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal and revised its estimates of the final reclamation costs. This estimate reflects that, with the proposed shutdown of SJGS Units 2 and 3 described above, the mine providing coal to SJGS will continue

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to operate through 2053, the anticipated life of SJGS. The current estimate for decommissioning the Four Corners mine reflects the operation of the mine through 2031, the term of the new coal supply agreement. Based on the 2014 estimates and PNM’s current ownership share of SJGS, PNM’s remaining payments for mine reclamation, in future dollars, are estimated to be $55.5 million for the surface mines at both SJGS and Four Corners and $93.3 million for the underground mine at SJGS as of September 30, 2015. At September 30, 2015 and December 31, 2014, liabilities, in current dollars, of $24.7 million and $25.7 million for surface mine reclamation and $9.3 million and $8.6 million for underground mine reclamation were recorded in other deferred credits. On June 1, 2012, the SJGS owners entered into a trust funds agreement to provide funding to compensate SJCC for post-term reclamation obligations under the UG-CSA. As part of the restructuring of SJGS ownership (see SJGS Ownership Restructuring Matters above), the SJGS owners and PNMR Development negotiated the terms of an amended agreement to fund post-term reclamation obligations under the CSA. The trust funds agreement requires each owner to enter into an individual trust agreement with a financial institution as trustee, create an irrevocable trust, and periodically deposit funding into the trust for the owner’s share of the mine reclamation obligation. Deposits, which are based on funding curves, must be made on an annual basis. PNM funded $1.0 million in 2014, $0.3 million in 2013, and $3.5 million in 2012. As part of the restructuring of SJGS ownership discussed above, the SJGS participants agreed to adjusted interim trust funding levels for 2015 and 2016. PNM’s funding level would increase by $4.6 million in 2015 and $4.3 million in 2016 from the 2014 level.

PNM collects a provision for surface and underground mine reclamation costs in its rates. The NMPRC has capped the amount that can be collected from ratepayers for final reclamation of the surface mines at $100.0 million . Previously, PNM recorded a regulatory asset for the $100.0 million and recovers the amortization of this regulatory asset in rates. If future estimates increase the liability for surface mine reclamation, the excess would be expensed at that time. In conjunction with the proposed shutdown of SJGS Units 2 and 3 to comply with the BART requirements of the CAA, an updated coal mine reclamation study was requested by the SJGS participants. As discussed under Coal Combustion Byproducts Waste Disposal above, SJGS currently disposes of CCBs from the plant in the surface mine pits adjacent to the plant. The updated coal mine reclamation study, which was performed in 2013, indicates reclamation costs have increased, including significant increases due to the proposed shutdown of SJGS Units 2 and 3, although the timing of payments will be delayed. The shutdown of Units 2 and 3 would reduce the amount of CCBs generated over the remaining life of SJGS, which could result in a significant increase in the amount of fill dirt required to remediate the underground mine area thereby increasing the overall reclamation costs. The reclamation amounts discussed above reflect PNM’s estimates of its share of the revised costs. Regulatory determinations made by the NMPRC may also affect the impact on PNM. PNM is currently unable to determine the outcome of these matters or the range of possible impacts.

Continuous Highwall Mining Royalty Rate

In August 2013, the DOI Bureau of Land Management (“BLM”) issued a proposed rulemaking that would retroactively apply the surface mining royalty rate of 12.5% to continuous highwall mining (“CHM”). Comments regarding the rulemaking were due on October 11, 2013 and PNM submitted comments in opposition to the proposed rule. There is no legal deadline for adoption of the final rule although the BLM has indicated that final action on the proposed rule is scheduled for March 2016.

SJCC utilized the CHM technique from 2000 to 2003 and, with the approval of the Farmington, New Mexico Field Office of BLM to reclassify the final highwall as underground reserves, applied the 8.0% underground mining royalty rate to coal mined using CHM and sold to SJGS. In March 2001, SJCC learned that the DOI Minerals Management Service (“MMS”) disagreed with the application of the underground royalty rate to CHM. In August 2006, SJCC and MMS entered into a settlement agreement tolling the statute of limitations on any administrative action to recover unpaid royalties until BLM issued a final, non-appealable determination as to the proper rate for CHM-mined coal. The proposed BLM rulemaking has the potential to terminate the tolling provision of the settlement agreement, and underpaid royalties of approximately $5 million for SJGS would become due if the proposed BLM rule is adopted as proposed. PNM’s share of any amount that is ultimately paid would be approximately 46.3% , none of which would be passed through PNM’s FPPAC. PNM is unable to predict the outcome of this matter.

Four Corners Severance Tax Assessment

On May 23, 2013, the New Mexico Taxation and Revenue Department (“NMTRD”) issued a notice of assessment for coal severance surtax, penalty, and interest totaling approximately $30 million related to coal supplied under the coal supply agreement for Four Corners. PNM’s share of any amounts paid related to this assessment would be approximately 9.4% , all of which would be passed through PNM’s FPPAC. For procedural reasons, on behalf of the Four Corners co-owners, including PNM, the coal

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supplier made a partial payment of the assessment and immediately filed a refund claim with respect to that partial payment in August 2013. NMTRD denied the refund claim. On December 19, 2013, the coal supplier and APS, on its own behalf and as operating agent for Four Corners, filed a complaint in the New Mexico District Court contesting both the validity of the assessment and the refund claim denial. On June 30, 2015, the court ruled that the assessment was not valid and further ruled that APS and the other Four Corners co-owners receive a refund of all of the contested amounts previously paid under the applicable tax statute. NMTRD filed a notice of appeal with the New Mexico Court of Appeals on August 31, 2015. PNM cannot predict the timing or outcome of this litigation. However, PNM does not expect the outcome to have a material impact on its financial position, results of operations, or cash flows.

PVNGS Liability and Insurance Matters

Public liability for incidents at nuclear power plants is governed by the Price-Anderson Act, which limits the liability of nuclear reactor owners to the amount of insurance available from both private sources and an industry retrospective payment plan. In accordance with the Price-Anderson Act, the PVNGS participants have insurance for public liability exposure for a nuclear incident totaling $13.4 billion per occurrence. Commercial insurance carriers provide $375 million and $13.0 billion is provided through a mandatory industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, PNM could be assessed retrospective premium adjustments. Based on PNM’s 10.2% interest in each of the three PVNGS units, PNM’s maximum potential retrospective premium assessment per incident for all three units is $38.9 million , with a maximum annual payment limitation of $5.7 million .

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion , a substantial portion of which must first be applied to stabilization and decontamination. These coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). Effective April 1, 2014, a sublimit of $2.25 billion for non-nuclear property damage losses has been enacted to the primary policy offered by NEIL. If NEIL’s losses in any policy year exceed accumulated funds, PNM is subject to retrospective premium assessments of $5.4 million for each retrospective premium assessment declared by NEIL’s Board of Directors. The insurance coverages discussed in this and the previous paragraph are subject to certain policy conditions, sublimits, and exclusions.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is concern in New Mexico about the use of water, including that used for power generation. PNM has secured groundwater rights in connection with the existing plants at Reeves Station, Rio Bravo, Afton, Luna, and Lordsburg. Water availability is not an issue for these plants at this time. However, prolonged drought, ESA activities, and a federal lawsuit by the State of Texas (suing the State of New Mexico over water allocations) could pose a threat of reduced water availability for these plants.

PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines to accommodate the possibility of inadequate precipitation in coming years. Since 2004, PNM has entered into agreements for voluntary sharing of the impacts of water shortages with tribes and other water users in the San Juan basin. This agreement has been extended through 2016. In addition, in the case of water shortage, PNM, APS, and BHP have reached agreement with the Jicarilla Apache Nation on a long-term supplemental contract relating to water for SJGS and Four Corners that runs through 2016. Although PNM does not believe that its operations will be materially affected by drought conditions at this time, it cannot forecast the weather or its ramifications, or how policy, regulations, and legislation may impact PNM should water shortages occur in the future.

In April 2010, APS signed an agreement on behalf of the PVNGS participants with five cities to provide cooling water essential to power production at PVNGS for forty years.

PVNGS Water Supply Litigation

In 1986, an action commenced regarding the rights of APS and the other PVNGS participants to the use of groundwater and effluent at PVNGS. APS filed claims that dispute the court’s jurisdiction over PVNGS’ groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those rights. In 1999, the Arizona Supreme Court issued a decision finding that certain groundwater rights may be available to the federal government and Indian tribes. In addition,

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the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on these issues has continued in the trial court. No trial dates have been set in these matters. PNM does not expect that this litigation will have a material impact on its results of operation, financial position, or cash flows.

San Juan River Adjudication

In 1975, the State of New Mexico filed an action in New Mexico District Court to adjudicate all water rights in the San Juan River Stream System, including water used at Four Corners and SJGS. PNM was made a defendant in the litigation in 1976. In March 2009, President Obama signed legislation confirming a 2005 settlement with the Navajo Nation. Under the terms of the settlement agreement, the Navajo Nation’s water rights would be settled and finally determined by entry by the court of two proposed adjudication decrees. The court issued an order in August 2013 finding that no evidentiary hearing was warranted in the Navajo Nation proceeding and, on November 1, 2013, issued a Partial Final Judgment and Decree of the Water Rights of the Navajo Nation approving the proposed settlement with the Navajo Nation. Several parties filed a joint motion for a new trial, which was denied by the court. A number of parties subsequently appealed to the New Mexico Court of Appeals. PNM has entered its appearance in the appellate case. No hearing dates or deadlines have been set at this time.

PNM is participating in this proceeding since PNM’s water rights in the San Juan Basin may be affected by the rights recognized in the settlement agreement as being owned by the Navajo Nation, which comprise a significant portion of water available from sources on the San Juan River and in the San Juan Basin. PNM is unable to predict the ultimate outcome of this matter or estimate the amount or range of potential loss and cannot determine the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. Final resolution of the case cannot be expected for several years. An agreement reached with the Navajo Nation in 1985, however, provides that if Four Corners loses a portion of its rights in the adjudication, the Navajo Nation will provide, for an agreed upon cost, sufficient water from its allocation to offset the loss.

Rights-of-Way Matter

On January 28, 2014, the County Commission of Bernalillo County, New Mexico passed an ordinance requiring utilities to enter into a use agreement and pay a yet to be determined fee as a condition to installing, maintaining, and operating facilities on county rights-of-way. The fee is purported to compensate the county for costs of administering, maintaining, and capital improvements to the rights-of-way. On February 27, 2014, PNM and other utilities filed a Complaint for Declaratory and Injunctive Relief in the United States District Court for the District of New Mexico challenging the validity of the ordinance. The court denied the utilities’ motion for judgment. The court further granted the County’s motion to dismiss the state law claims. The utilities filed an amended complaint reflecting the two federal claims remaining before the federal court. The utilities also filed a complaint in Bernalillo County, New Mexico District Court reflecting the state law counts dismissed by the federal court. In subsequent briefing in federal court, the County filed a motion for judgment on one of the utilities’ claims, which was granted by the court, leaving a claim regarding telecommunications service as the remaining federal claim. This matter is ongoing in state court. The utilities and Bernalillo County reached a standstill agreement whereby the County would not take any enforcement action against the utilities pursuant to the ordinance during the pendency of the litigation, but not including any period for appeal of a judgment, or upon 30 days written notice by either the County or the utilities of their intention to terminate the agreement. If the challenges to the ordinance are unsuccessful, PNM believes any fees paid pursuant to the ordinance would be considered franchise fees and would be recoverable from customers. PNM is unable to predict the outcome of this matter or its impact on PNM’s operations.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS alleging SPS overcharged PNM for deliveries of energy through its fuel cost adjustment clause practices and that rates for sales to PNM were excessive. PNM also intervened in a proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause practices and issues relating to demand cost allocation (the “Golden Spread Proceeding”). In addition, PNM intervened in a proceeding filed by SPS to revise its rates for sales to PNM (“SPS 2006 Rate Proceeding”). In 2008, FERC issued its order in the Golden Spread Proceeding affirming an ALJ decision that SPS violated its fuel cost adjustment clause tariffs, but shortening the refund period applicable to the violation of the fuel cost adjustment clause issues that had been ordered by the ALJ. FERC also reversed the decision of the ALJ, which had been favorable to PNM, on the demand cost allocation issues. PNM and SPS filed petitions for rehearing and clarification of the scope of the remedies that were ordered and seeking reversal of various rulings in

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the order. On August 15, 2013, FERC issued separate orders in the Golden Spread Proceeding and in the SPS 2006 Rate Proceeding. The order in the Golden Spread Proceeding determined that PNM was not entitled to refunds for SPS’ fuel cost adjustment clause practices. That order and the order in the SPS 2006 Rate Proceeding decided the demand cost allocation issues using the method that PNM had advocated. PNM, SPS, and other customers of SPS filed requests for rehearing of these orders. On August 28, 2015, SPS filed settlement documentation with FERC, including a settlement agreement to which PNM was a party. If approved by FERC, the settlement would resolve all outstanding fuel cost adjustment and rate issues between SPS and PNM. Under the settlement, SPS would pay PNM $4.2 million , including interest through December 31, 2014. Of this amount, $2.6 million would be passed back to PNM’s customers through its FPPAC. FERC staff filed comments indicating they were not opposed to the settlement. FERC approved the settlement on October 29, 2015, at which time it was recorded by PNM.

Navajo Nation Allottee Matters

A putative class action was filed against PNM and other utilities in February 2009 in the United States District Court for the District of New Mexico. Plaintiffs claim to be allottees, members of the Navajo Nation, who pursuant to the Dawes Act of 1887, were allotted ownership in land carved out of the Navajo Nation and allege that defendants, including PNM, are rights-of-way grantees with rights-of-way across the allotted lands and are either in trespass or have paid insufficient fees for the grant of rights-of-way or both. In March 2010, the court ordered that the entirety of the plaintiffs’ case be dismissed. The court did not grant plaintiffs leave to amend their complaint, finding that they instead must pursue and exhaust their administrative remedies before seeking redress in federal court. In May 2010, plaintiffs filed a Notice of Appeal with the Bureau of Indian Affairs (“BIA”), which was denied by the BIA Regional Director. In May 2011, plaintiffs appealed the Regional Director’s decision to the DOI, Office of Hearings and Appeals, Interior Board of Indian Appeals. Following briefing on the merits, on August 20, 2013, that board issued a decision upholding the Regional Director’s decision that the allottees had failed to perfect their appeals, and dismissed the allottees’ appeals, without prejudice. The allottees have not refiled their appeals. Although this matter was dismissed without prejudice, PNM considers the matter concluded. However, PNM continues to monitor this matter in order to preserve its interests regarding any PNM-acquired rights-of-way.

In a separate matter, in September 2012, 43 landowners claiming to be Navajo allottees filed a notice of appeal with the BIA appealing a March 2011 decision of the BIA Regional Director regarding renewal of a right-of-way for a PNM transmission line. The allottees, many of whom are also allottees in the above matter, generally allege that they were not paid fair market value for the right-of-way, that they were denied the opportunity to make a showing as to their view of fair market value, and thus denied due process. On January 6, 2014, PNM received notice that the BIA, Navajo Region, requested a review of an appraisal report on 58 allotment parcels. After review, the BIA concluded it would continue to rely on the values of the original appraisal. On March 27, 2014, while this matter was stayed, the allottees filed a motion to dismiss their appeal with prejudice. On April 2, 2014, the allottees’ appeal was dismissed with prejudice. Subsequent to the dismissal, PNM received a letter from counsel on behalf of what appears to be a subset of the 43 landowner allottees involved in the appeal, notifying PNM that the specified allottees were revoking their consents for renewal of right of way on six specific allotments. On January 22, 2015, PNM received a letter from the BIA Regional Director identifying ten allotments with rights-of-way renewals that were previously contested. The letter indicated that the renewals were not approved by the BIA because the previous consent obtained by PNM was later revoked, prior to BIA approval, by the majority owners of the allotments. It is the BIA Regional Director’s position that PNM must re-obtain consent from these landowners. On July 13, 2015, PNM filed a condemnation action in the United States District Court for the District of New Mexico regarding the approximately 15.49 acres of land at issue. On September 18, 2015, the allottees filed a separate complaint against PNM for federal trespass. PNM cannot predict the outcome of this litigation.


(12)	Regulatory and Rate Matters

The Company is involved in various regulatory matters, some of which contain contingencies that are subject to the same uncertainties as those described in Note 11. Additional information concerning regulatory and rate matters is contained in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

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PNM

New Mexico General Rate Case

On December 11, 2014, PNM filed an application for revision of electric retail rates based upon a calendar year 2016 future test year (“FTY”) period. The application proposed a revenue increase of $107.4 million , effective January 1, 2016. PNM’s proposed ROE was 10.5% . The requested base rate increase, combined with other rate changes, represented an average bill increase of 7.69% . PNM requested this increase to account for infrastructure investments made since the last rate case and investments needed in the next two years to provide reliable service to PNM’s retail customers, as well as to reflect the declining sales growth in PNM’s service territory. The primary driver of PNM’s identified revenue deficiency, accounting for approximately 92% of the rate increase, was related to infrastructure investments and the recovery of those investment dollars, including depreciation. PNM’s success with energy efficiency programs was a contributing factor to the decline in PNM’s energy sales since the last rate case and accounted for the balance of the rate increase after accounting for offsetting cost reductions. PNM proposed several changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals included increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, an access charge to customers installing distributed generation systems after December 31, 2015, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. Several parties filed briefs, which alleged that PNM’s application was incomplete and challenged the distributed generation charge, as well as other aspects of PNM’s filing. PNM filed a response brief addressing these matters.

On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete and reject it on the grounds that it does not comply with the FTY rule. The Hearing Examiner cited procedural defects in the filing, including a lack of fully functional electronic files and appropriate justification of certain costs in the future test year period. PNM did not agree with the Hearing Examiner’s Initial Recommended Decision and filed exceptions on April 30, 2015. PNM’s exceptions argued that PNM substantively met the filing requirements of the applicable New Mexico Statutes and NMPRC Rules, the Initial Recommended Decision established an unreasonable standard for future test year filing requirements, and the recommendations placing limits on the timing of the test period relative to the base period effectively nullified the future test year statute. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision regarding the completeness of PNM’s application and dismissed PNM’s application.

On August 29, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase, including base fuel revenues, of $123.5 million . PNM’s new application is based on a FTY period beginning October 1, 2015, which meets the NMPRC’s current interpretation of the FTY statute discussed below. The proposed ROE is 10.5% . The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and the recovery of those investment dollars, including depreciation based on an updated depreciation study, and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals include increased customer and demand charges, a revenue decoupling pilot program applicable to residential and small power customers, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. PNM requested that the proposed new rates become effective beginning in July 2016. The NMPRC’s designated Hearing Examiner has established a procedural schedule that anticipates a public hearing on the proposed new rates will begin on March 14, 2016.

Proceeding Regarding Definition of Future Test Year

On June 25, 2015, PNM filed a Notice of Appeal to the NMSC, challenging the NMPRC’s June 3, 2015 written order. There is no required timeframe for the NMSC to act on PNM’s appeal. Two other utilities have filed separate notices of appeals with the NMSC and the ABCWUA filed a notice of cross appeal. On July 15, 2015, the NMPRC filed its Motion for Stay of Proceeding at the NMSC and for Remand of Jurisdiction, seeking the ability to conduct a rulemaking process on the definition

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and parameters of a FTY for rate cases. PNM opposed the motion. On July 31, 2015, PNM and the NMPRC filed a joint motion for a temporary 30 -day stay and remand of PNM’s appeal so that the NMPRC can reconsider its FTY order in PNM’s 2014 rate case; this motion is opposed by ABCWUA. The NMSC has not acted on the pending motions.

Renewable Portfolio Standard

The REA establishes a mandatory RPS requiring a utility to acquire a renewable energy portfolio equal to 10% of retail electric sales by 2011, 15% by 2015, and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified.” The current diversity requirements, which are subject to the limitation of the RCT, are 30% wind, 20% solar, 3% distributed generation, and 5% other.

The REA provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities that they recover costs incurred consistent with approved procurement plans, and requires the NMPRC to establish a RCT for the procurement of renewable resources to prevent excessive costs being added to rates. Currently, the RCT is set at 3% of customers’ annual electric charges. PNM is recovering certain renewable procurement costs from customers through a rate rider. See Renewable Energy Rider below.

PNM filed its 2014 renewable energy procurement plan on July 1, 2013. The plan meets RPS and diversity requirements within the RCT in 2014 and 2015. PNM’s procurements included 50,000 MWh of wind generated RECs in 2014, the construction by December 31, 2014 of 23 MW of PNM-owned solar PV facilities at a cost of $46.7 million , a 20 -year PPA for the output of Red Mesa Wind, an existing wind generator having an aggregate capacity of 102 MW, beginning January 1, 2015 at a first year cost estimated to be $5.8 million , and the purchase of 120,000 MWh of wind RECs in 2015. The NMPRC approved the plan on December 18, 2013. PNM made procurements in 2014 consistent with the approved plan. Construction of the solar PV facilities was completed in 2014 at a cost of $46.5 million .

PNM filed its 2015 renewable energy procurement plan on June 2, 2014. The plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM’s proposed new procurements included the construction by December 31, 2015 of 40 MW of PNM-owned solar PV facilities at a cost of $78.0 million , which is included in PNM’s current construction expenditure forecast. The proposed 40 MW solar facilities are identified as being a cost-effective resource in PNM’s application to retire SJGS Units 2 and 3 (Note 11). A stipulated settlement was approved by the NMPRC on November 26, 2014. Under the agreement, the costs of the 40 MW of solar would be included in base rates rather than through PNM’s renewable energy rider and have been included in rates requested in the New Mexico General Rate Case discussed above. In addition, PNM would be required to make additional renewable energy procurements in the event that the prior year’s actual renewable energy procurements did not meet the RPS for that year based on actual retail sales and the actual RCT at a not-to-exceed price of $3.00 per MWh in 2013 and 2014. In the fourth quarter of 2014 and the second quarter of 2015, PNM procured the additional renewable resources to meet the 2013 and 2014 RPS requirement for $0.1 million and less than $0.1 million .

PNM filed its 2016 renewable energy procurement plan on June 1, 2015. The plan meets RPS and diversity requirements within the RCT in 2016 and 2017. The plan does not propose any significant new procurements. A public hearing on the 2016 procurement plan was held in September 2015 and an order from the NMPRC is expected by November 30, 2015. The Hearing Examiner issued a Recommended Decision on October 20, 2015 that recommends approval of the plan and the proposed rider adjustment with some minor modifications. These adjustments do not affect the amount of revenue that will be collected through the rider in 2016.

Renewable Energy Rider

The NMPRC has authorized PNM to recover certain renewable procurement costs through a rate rider billed on a per KWh basis. The rider will terminate upon a final order in PNM’s next electric rate case unless the NMPRC authorizes PNM to continue it. As a separate component of the rider, if PNM’s earned return on jurisdictional equity in a calendar year, adjusted for weather and other items not representative of normal operations, exceeds 10.5% , PNM would be required to refund the amount over 10.5% to customers during May through December of the following year. PNM made filings with the NMPRC demonstrating that it had not exceeded the 10.5% return for 2013 and 2014 on April 1, 2014 and April 1, 2015. PNM recorded revenues from the rider of $34.3 million in 2014. In PNM’s 2015 renewable energy procurement plan case, the NMPRC approved a rate, which is designed to collect $44.7 million in 2015. On February 27, 2015, PNM filed a notice to reduce the amount to be collected during 2015 to

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$43.0 million , reflecting a reconciliation of expenses and revenues under the rider during 2014 and updated cost estimates for 2015. The rate reduction was due to an over-collection in 2014 that primarily resulted from lower than projected generation of geothermal renewable energy. The revision was implemented on April 27, 2015. PNM proposes to recover $42.4 million through the rider in 2016 in its 2016 renewable energy procurement plan discussed above.

Energy Efficiency and Load Management

Program Costs

Public utilities are required by the Efficient Use of Energy Act to achieve specified levels of energy savings and to obtain NMPRC approval to implement energy efficiency and load management programs. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue. PNM’s costs to implement approved programs are recovered through a rate rider. In 2013, this act was amended to set an annual program budget equal to 3% of an electric utility’s annual revenue.

On October 6, 2014, PNM filed an energy efficiency program application for programs proposed to be offered beginning in June 2015. The filing included proposed program costs of $25.8 million plus a proposed profit incentive. The proposed energy efficiency budget and plan are consistent with the 2013 amendments to the Efficient Use of Energy Act. PNM and the NMPRC staff filed a stipulation on January 30, 2015. A public hearing on the stipulation was held in February 2015. The Hearing Examiner issued a Certification of Stipulation on April 10, 2015 recommending that the NMPRC approve the stipulation in its entirety and to allow PNM to continue recovering the incentive contemporaneously with program costs. On April 29, 2015, the NMPRC approved the certification. Upon approval, the stipulation established program budgets and the incentive amounts discussed below.

Disincentives/Incentives

The Efficient Use of Energy Act requires the NMPRC to remove utility disincentives to implementing energy efficiency and load management programs and to provide incentives for such programs. In 2010, PNM began implementing the NMPRC rule that authorized electric utilities to collect rate adders to remove disincentives and to provide incentives for energy and demand savings related to energy efficiency and demand response programs. In November 2013, the NMPRC issued an order authorizing PNM to recover an incentive equal to 7.6% of annual program costs beginning with program implementation in December 2013. Based on PNM’s currently approved program costs, this equates to an estimated annual incentive of $1.7 million .

In PNM’s 2014 energy efficiency program application, PNM proposed an energy efficiency incentive of $2.1 million . PNM’s proposed incentive was based upon a shared benefits methodology and is similar in amount to previous PNM incentives authorized by the NMPRC. Under the terms of the January 30, 2015 stipulation discussed above, the incentive amount would be $1.7 million in 2015 and $1.8 million in 2016 assuming threshold level of savings are achieved.

Energy Efficiency Rulemaking

On May 17, 2012, the NMPRC issued a NOPR that would have amended the NMPRC’s energy efficiency rule to authorize use of a decoupling mechanism to recover certain fixed costs of providing retail electric service as the mechanism for removal of disincentives associated with the implementation of energy efficiency programs. The proposed rule also addressed incentives associated with energy efficiency. On July 26, 2012, the NMPRC closed the proposed rulemaking and opened a new energy efficiency rulemaking docket that may address decoupling and incentives. Workshops to develop a proposed rule have been held, but no order proposing a rule has been issued. PNM is unable to predict the outcome of this matter.

On October 2, 2013, the NMPRC issued a NOPR and a proposed rule to implement amendments to the New Mexico Efficient Use of Energy Act. The NMPRC issued an order on October 8, 2014 adopting the proposed rule, which includes a provision that limits incentive awards to an amount equal to the utility’s WACC times its approved annual program costs.

Integrated Resource Plan

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(Unaudited)

and 3. PNM indicated that it planned to meet its anticipated long-term load growth with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities. Consistent with statute and NMPRC rule, PNM incorporated a public advisory process into the development of its 2014 IRP. On July 31, 2014, several parties requested the NMPRC not to accept the 2014 IRP as compliant with NMPRC rule because to do so could affect the pending proceeding on PNM’s application to abandon SJGS Units 2 and 3 and for CCNs for certain replacement resources (Note 11) and because they assert that the IRP does not conform to the NMPRC’s IRP rule. Certain parties also ask that further proceedings on the IRP be held in abeyance until the conclusion of the pending abandonment/CCN proceeding. The NMPRC issued an order in August 2014 that dockets a case to determine whether the IRP complies with applicable NMPRC rules. The order also holds the case in abeyance pending the issuance of final, non-appealable orders in PNM’s 2015 renewable energy procurement plan case and its application to retire SJGS Units 2 and 3. The Stipulated Settlement regarding PNM’s application to abandon SJGS Units 2 and 3 described in Note 11 would, if approved by the NMPRC, result in the closing of the 2014 IRP docket without further NMPRC action.

San Juan Generating Station Units 2 and 3 Retirement

On December 20, 2013, PNM filed an application at the NMPRC to retire SJGS Units 2 and 3 on December 31, 2017. On October 1, 2014, PNM and certain parties to the case filed a stipulation with the NMPRC proposing a settlement of this case. Other parties opposed the stipulated agreement. The Hearing Examiner issued a Certification of Stipulation on April 8, 2015 that recommended rejection of the agreement as proposed, and recommended several modifications to the agreement. On August 13, 2015, PNM and certain parties to the case filed an agreement that, if approved by the NMPRC, would modify the stipulation and settle all issues in the case. Others oppose the modified stipulation. Additional information concerning the NMPRC filing, including a summary of the terms of the modified stipulation, and related proceedings before the NMSC is set forth in Note 11. PNM anticipates an order from the NMPRC in the fourth quarter of 2015. On September 25, 2015, PNM made an application at FERC seeking certain approvals necessary for implementation of the restructured SJGS participation agreements. PNM is unable to predict the outcome of these matters.

Four Corners Right of First Refusal

On February 17, 2015, PNM received notice from EPE that EPE has entered into an agreement to sell its 7% interest in Four Corners to APS, thereby triggering PNM’s ability to exercise its right of first refusal (“ROFR”) to acquire a portion of EPE’s interest in Four Corners. PNM notified the NMPRC about receipt of the notice and advised the NMPRC that PNM does not intend to exercise its rights under the ROFR. The ROFR expired unexercised 120 days after the date of EPE’s notice.

Application for Certificate of Convenience and Necessity

On June 30, 2015, PNM filed an application for a CCN for a 187 MW gas plant to be located at SJGS. This resource was identified as a replacement resource in PNM’s application to retire SJGS Units 2 and 3. PNM estimated the cost of the facility, which would be located at SJGS, to be $133.2 million . PNM identified the necessary in-service date to be in the first half of 2018. On July 9, 2015, a party to the SJGS Unit 2 and 3 retirement case filed a motion to consolidate this CCN case with the retirement case, which motion was subsequently withdrawn. The NMPRC has scheduled a hearing on the requested CCN to begin on February 22, 2016. PNM intends to re-evaluate the timing and resource requirements for installation of the natural gas-fired unit requested in the CCN proceeding, including the potential for a smaller unit, along with other possible power resources, taking into consideration PNM’s recently revised lower load forecast and the impacts of the NEC settlement agreement recently filed with FERC, which is discussed below. This process could delay the hearing on the CCN, as well as its approval, and the in-service date of a replacement power resource, PNM’s current construction expenditure forecast includes a 100 MW gas-fired unit with an estimated cost of $101.8 million. PNM cannot predict the outcome of this proceeding.

Formula Transmission Rate Case

In a settlement of a prior rate case for PNM’s transmission customers, the parties agreed that if PNM filed for a formula based rate change, no party would oppose the general principle of a formula rate, although the parties could object to particular aspects of the formula. On December 31, 2012, PNM filed an application with FERC for authorization to move from charging stated rates for wholesale electric transmission service to a formula rate mechanism pursuant to which rates for wholesale transmission service are calculated annually in accordance with an approved formula. The proposed formula includes updating cost of service components, including investment in plant and operating expenses, based on information contained in PNM’s annual

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

financial report filed with FERC, as well as including projected large transmission capital projects to be placed into service in the following year. The projections included are subject to true-up in the following year formula rate. Certain items, including changes to return on equity and depreciation rates, require a separate filing to be made with FERC before being included in the formula rate. As filed, PNM’s request would result in a $3.2 million wholesale electric transmission rate increase, based on PNM’s 2011 data and a 10.81% return on equity (“ROE”), and authority to adjust transmission rates annually based on an approved formula.

On March 1, 2013, FERC issued an order (1) accepting PNM’s revisions to its rates for filing and suspending the proposed revisions to become effective August 2, 2013, subject to refund; (2) directing PNM to submit a compliance filing to establish its ROE using the median, rather than the mid-point, of the ROEs from a proxy group of companies; (3) directing PNM to submit a compliance filing to remove from its rate proposal the acquisition adjustment related to PNM’s 60% ownership of the EIP transmission line, which was acquired in 2003; and (4) setting the proceeding for hearing and settlement judge procedures. PNM would be allowed to make a separate filing related to recovery of the EIP acquisition adjustment. On April 1, 2013, PNM made the required compliance filing. On June 3, 2013, PNM made additional filings incorporating final 2012 data into the formula rate request. The updated formula rate would result in a $1.3 million rate increase over the rates approved by FERC approved in the previous rate case. The new rates apply to all of PNM’s wholesale electric transmission service customers. PNM filed for rehearing of FERC’s order regarding the ROE. On June 10, 2013, FERC denied PNM’s motion for rehearing regarding FERC’s order requiring PNM to use the median, instead of the midpoint, to calculate its ROE for the formula rate case. On August 2, 2013, the new rates went into effect, subject to refund. On May 1, 2014, PNM updated its formula rate incorporating 2013 data resulting in a $0.5 million rate increase over the then current rates. PNM filed the updated rate request with FERC on May 30, 2014, at which time the new rates became effective, subject to refund. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. Additionally, the parties filed a motion to implement the settled rates effective April 1, 2015. On March 25, 2015, the ALJ issued an order authorizing the interim implementation of settled rates on April 1, 2015, subject to refund. There is no required time frame for FERC to act upon the settlement.

Firm-Requirements Wholesale Customers

Navopache Electric Cooperative, Inc.

In September 2011, PNM filed an unexecuted amended PSA between PNM and NEC with FERC. NEC filed a protest to PNM’s filing with FERC. In November 2011, FERC issued an order accepting the filing to be effective April 14, 2012, subject to refund, and set the proceeding for settlement. The parties finalized a settlement agreement and amended PSA, which were filed with FERC on December 6, 2012. The settlement agreement and amended PSA provided for an annual increase in revenue of $5.3 million and an extension of the contract for 10 years through December 31, 2035. On April 5, 2013, FERC approved the settlement agreement and the amended PSA. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the PSA.

On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the amended PSA. On May 8, 2015, PNM filed an intervention and protest with FERC requesting that FERC deny NEC’s petition or to proceed with a public hearing if the petition is not denied. On July 16, 2015, FERC issued an order setting the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA and held the hearing in abeyance to provide time for settlement judge procedures.

Following proceedings before a settlement judge, PNM and NEC entered into, and filed with FERC, a settlement agreement on October 29, 2015 that includes certain amendments to the PSA and related contracts on file with FERC that, if approved by FERC, would settle this matter. Under the settlement agreement, PNM would continue to serve all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those currently provided under the PSA. In 2016, PNM would serve all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC would also pay certain third-party transmission costs that it did not pay in 2014. The PSA and related transmission agreements would terminate on December 31, 2016. In 2017, PNM would serve 10 MW of NEC’s load under a short term coordination tariff at a rate lower than provided under the PSA. The filing requests that, pending approval of the agreement, FERC allow interim rates, which reflect the settlement, to be charged under the PSA. PNM is unable to predict if FERC will allow the interim rate request or approve the settlement.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

City of Gallup, New Mexico Contract

PNM provided both energy and power services to Gallup, previously PNM’s second largest firm-requirements wholesale customer, under an electric service agreement that was to expire on June 30, 2013. On May 1, 2013, PNM and Gallup agreed to extend the term of the agreement to June 30, 2014 and to increase the demand and energy rates under the agreement.

On September 26, 2013, Gallup issued a request for proposals for long-term power supply. PNM submitted a proposal in November 2013. On March 26, 2014, Gallup notified PNM that the contract for long-term power supply had been awarded to another utility. PNM’s contract with Gallup ended on June 29, 2014. PNM’s revenues for power sold under the Gallup contract were $6.1 million in the six months ended June 30, 2014. PNM’s New Mexico General Rate Case discussed above reflects a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

In conjunction with the termination of PNM’s electric service agreement with Gallup, Gallup purchased substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup. This sale resulted in a gain of $1.1 million , which PNM recorded in other income during the three months ended June 30, 2015.

TNMP

Advanced Meter System Deployment

In July 2011, the PUCT approved a settlement and authorized an AMS deployment plan that permits TNMP to collect $113.4 million in deployment costs through a surcharge over a 12 -year period. TNMP began collecting the surcharge on August 11, 2011. Deployment of advanced meters began in September 2011 and is scheduled to be completed over a 5 -year period.

In February 2012, the PUCT opened a proceeding to consider the feasibility of an “opt-out” program for retail consumers that wish to decline receipt of an advanced meter. The PUCT requested comments and held a public meeting on various issues. However, various individuals filed a petition with the PUCT seeking a moratorium on any advanced meter deployment. The PUCT denied the petition and an appeal was filed with the Texas District Court on September 28, 2012.

The PUCT adopted a rule on August 15, 2013 creating a non-standard metering service for retail customers choosing to decline standard metering service via an advanced meter. The cost of providing non-standard metering service is to be borne by opt-out customers through an initial fee and ongoing monthly charge. On June 20, 2014, the PUCT approved a settlement permitting TNMP to recover $0.2 million in costs through initial fees ranging from $63.97 to $168.61 and ongoing annual expenses of $0.5 million collected through a $36.78 monthly fee. The settlement presumes up to 1,081 consumers will elect the non-standard meter service, but preserves TNMP’s rights to adjust the fees if the number of anticipated consumers differs from that estimate. TNMP notified all appropriate customers that they could elect non-standard metering. As of October 23, 2015, 94 customers have made the election. TNMP does not expect the implementation of non-standard metering service to have a material impact on its financial position, results of operations, or cash flows.

On October 2, 2015, TNMP filed a reconciliation of the costs and savings of its AMS deployment program with the PUCT. Those costs include $71.0 million in capital costs and $18.0 million in operation and maintenance expenses. However, since the deployment is not complete and the total program costs to date are $1.5 million below the original approved forecasts, TNMP is not requesting a change to its monthly surcharge amount. The reconciliation is subject to prudency and reasonableness review by the PUCT. No procedural schedule or hearings have been set for this matter.

Energy Efficiency

TNMP recovers the costs of its energy efficiency programs through an energy efficiency cost recovery factor, which includes projected program costs, under or over collected costs from prior years, rate case expenses, and performance bonuses (if the programs exceed mandated savings goals). On October 25, 2013, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.6 million , including a performance bonus for 2012 of $0.7 million , beginning March 1, 2014. On September 11, 2014, the PUCT approved a settlement that permitted TNMP to collect an aggregate of $5.7 million beginning March 1, 2015, including a performance bonus for 2013 of $1.5 million . On May 29, 2015, TNMP filed its 2016 energy efficiency cost recovery factor application with the PUCT requesting recovery of $6.0 million , including a performance bonus of $0.7 million ,

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

to be collected beginning March 1, 2016. The parties entered a unanimous stipulation approving TNMP’s request on August 10, 2015. On September 11, 2015, the PUCT approved the request. TNMP records incentive bonuses upon approval by the PUCT.

Transmission Cost of Service Rates

TNMP can update its transmission rates twice per year to reflect changes in its invested capital. Updated rates reflect the addition and retirement of transmission facilities, including appropriate depreciation, federal income tax and other associated taxes, and the approved rate of return on such facilities. The following sets forth TNMP’s most recent interim transmission cost rate increases:



Effective Date	Approved Increase in Rate Base		Annual Increase in Revenue
	(in millions)
September 17, 2013	$	18.1	$	2.8
March 13, 2014	18.2		2.9
September 8, 2014	25.2		4.2
March 16, 2015	27.1		4.4
September 10, 2015	7.0		1.4


(13)	Income Taxes

On April 4, 2013, New Mexico House Bill 641 was signed into law. One of the provisions of the bill was to reduce the New Mexico corporate income tax rate from 7.6% to 5.9% . The rate reduction is being phased in from 2014 to 2018. In accordance with GAAP, PNMR and PNM adjusted accumulated deferred income taxes to reflect the tax rate at which the balances are expected to reverse during the period that includes the date of enactment. The portion of the adjustment related to PNM’s regulated activities was recorded as a reduction in deferred tax liabilities, which was offset by an increase in a regulatory liability, on the assumption that PNM will be required to return the benefit to customers over time. The portion of the adjustment that is not related to PNM’s regulated activities was recorded in PNMR’s Corporate and Other segment as a reduction in deferred tax assets and an increase in income tax expense. Changes in the estimated timing of reversals of deferred tax assets and liabilities will result in refinements of the impacts of this change in tax rates being recorded periodically until 2018, when the rate reduction is fully phased in. In the three months ended March 31, 2015 and 2014, PNM’s regulatory liability was reduced by $2.0 million and $4.6 million , which increased deferred tax liabilities. Deferred tax assets not related to PNM’s regulatory activities were increased by $0.7 million in the three months ended March 31, 2015, reducing income tax expense by $0.5 million for PNM and $0.2 million for the Corporate and Other segment, and were reduced by $0.2 million in the three months ended March 31, 2014 increasing income tax expense in the Corporate and Other segment.

In June 2014, the Company settled the IRS examination of income tax years 2003 and 2005 through 2008. As a result of the settlement, the Company received net federal tax refunds of $2.0 million . The IRS examination resulted in the settlement of certain issues for which the Company had previously reflected liabilities related to uncertain tax positions. The settlement of the IRS examination, including the uncertain tax position matters, resulted in PNMR recording an income tax benefit of $0.2 million on a consolidated basis in the three months ended June 30, 2014. PNM recorded an income tax expense of $1.1 million , TNMP reflected no impact, and an income tax benefit of $1.3 million was recorded in PNMR’s Corporate and Other segment.

On December 19, 2014, the Tax Increase Prevention Act of 2014, which retroactively extended fifty percent bonus tax depreciation for 2014, was signed into law. Due to provisions in the act, taxes payable to the State of New Mexico were reduced. The act resulted in an impairment of New Mexico net operating loss carryforwards, which was recorded as additional income tax expense during the year ended December 31, 2014. During the three months ended March 31, 2015, the impairment of the New Mexico net operating loss carryforward was refined, resulting in an additional impairment of $1.0 million , after federal income tax benefit, $0.7 million of which was recorded by PNM and $0.3 million was recorded in the Corporate and Other segment. The

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

estimate was further refined as of September 30, 2015 that resulted in an additional impairment of the New Mexico net operating loss carryforward of $0.3 million , of which $0.2 million was recorded by PNM and $0.1 million was recorded in the Corporate and Other segment. This refinement resulted in an additional impairment of the New Mexico wind energy production tax credit carryforwards of $1.0 million , which was recorded in the Corporate and Other segment. TNMP had no such impairments.


(14)	Related Party Transactions

PNMR, PNM, and TNMP are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR and its subsidiaries in accordance with shared services agreements. The table below summarizes the nature and amount of related party transactions of PNMR, PNM, and TNMP:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2015		2014		2015		2014
	(In thousands)
Services billings:
PNMR to PNM	$	21,894	$	20,813	$	65,961	$	64,069
PNMR to TNMP	6,707		6,471		20,366		20,695
PNM to TNMP	136		142		424		402
TNMP to PNMR	—		20		—		21
Interest billings:
PNMR to TNMP	34		65		167		245
PNMR to PNM	10		1		38		55
PNM to PNMR	24		28		79		79
Income tax sharing payments:
PNMR to PNM	—		—		1,450		—
PNMR to TNMP	—		—		—		—


(15)	Goodwill

The excess purchase price over the fair value of the assets acquired and the liabilities assumed by PNMR for its 2005 acquisition of TNP was recorded as goodwill and was pushed down to the businesses acquired. In 2007, the TNMP assets that were included in its New Mexico operations, including goodwill, were transferred to PNM.

GAAP requires the Company to evaluate its goodwill for impairment annually at the reporting unit level or more frequently if circumstances indicate that the goodwill may be impaired. PNMR's reporting units that have goodwill are PNM and TNMP. Application of the impairment test requires judgment, including the identification of reporting units, assignment of assets and liabilities to reporting units, and determination of the fair value of each reporting unit.

GAAP provides that in certain circumstances an entity may perform a qualitative analysis to conclude that the goodwill of a reporting unit is not impaired. Under a qualitative assessment an entity considers macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other relevant entity-specific events affecting a reporting unit, as well as whether a sustained decrease (both absolute and relative to its peers) in share price had occurred. An entity considers the extent to which each of the adverse events and circumstances identified could affect the comparison of a reporting unit's fair value with its carrying amount. More weight is placed on the events and circumstances that most affect a reporting unit's fair value or the carrying amount of its net assets. An entity also considers positive and mitigating events and circumstances that may affect its determination of whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. An entity evaluates, on the basis of the weight of evidence, the significance of all identified events and circumstances in the context of determining whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If, after assessing the totality of events or circumstances, an entity determines that it is not more likely than not that the fair value of a reporting unit is less than its carrying amount, a quantitative analysis is not required.

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PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In other circumstances, an entity may perform a quantitative analysis to reach the conclusion regarding impairment with respect to a reporting unit. The first step of the quantitative impairment test requires an entity to compare the fair value of the reporting unit with its carrying value, including goodwill. If as a result of this analysis, the entity concludes there is an indication of impairment in a reporting unit having goodwill, the entity is required to perform the second step of the impairment analysis, determining the amount of goodwill impairment to be recorded. The amount is calculated by comparing the implied fair value of the goodwill to its carrying amount. This exercise would require the entity to allocate the fair value determined in step one to the individual assets and liabilities of the reporting unit. Any remaining fair value would be the implied fair value of goodwill on the testing date. To the extent the recorded amount of goodwill of a reporting unit exceeds the implied fair value determined in step two, an impairment loss would be reflected in results of operations.

An entity may choose to perform a quantitative analysis without performing a qualitative analysis and may perform a qualitative analysis for certain reporting units but a quantitative analysis for others. For the annual evaluations performed as of April 1, 2015 and 2014, PNMR utilized a qualitative analysis for the TNMP reporting unit and a quantitative analysis for the PNM reporting unit. For the PNM reporting unit, a discounted cash flow methodology was primarily used to estimate the fair value of the reporting unit. This analysis requires significant judgments, including estimation of future cash flows, which is dependent on internal forecasts, estimation of long-term growth rates for the business, and determination of appropriate weighted average cost of capital for each reporting unit. Changes in these estimates and assumptions could materially affect the determination of fair value and the conclusion of impairment.

The annual evaluations performed as of April 1, 2015 and 2014 did not indicate impairments of the goodwill of any of PNMR’s reporting units. The April 1, 2015 and 2014 quantitative evaluations indicated the fair value of the PNM reporting unit, which has goodwill of $51.6 million , exceeded its carrying value by approximately 25% and 30% . The last quantitative evaluation performed for the TNMP reporting unit on April 1, 2012 indicated the fair value of the TNMP reporting unit, which has goodwill of $226.7 million , exceeded its carrying value by approximately 26% . Since the April 1, 2015 annual evaluation, there have been no indications that the fair values of the reporting units with recorded goodwill have decreased below the carrying values. Additional information concerning the Company’s goodwill is contained in Note 20 of Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations for PNMR is presented on a combined basis, including certain information applicable to PNM and TNMP. The MD&A for PNM and TNMP is presented as permitted by Form 10-Q General Instruction H(2). This report uses the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. A reference to a “Note” in this Item 2 refers to the accompanying Notes to Condensed Consolidated Financial Statements (Unaudited) included in Item 1, unless otherwise specified. Certain of the tables below may not appear visually accurate due to rounding.

MD&A FOR PNMR

EXECUTIVE SUMMARY

Overview and Strategy

PNMR is a holding company with two regulated utilities serving approximately 758,000 residential, commercial, and industrial customers and end-users of electricity in New Mexico and Texas. PNMR’s electric utilities are PNM and TNMP.

Strategic Goals

PNMR is focused on achieving the following strategic goals:


•	Earning authorized returns on regulated businesses


•	Delivering above industry-average earnings and dividend growth


•	Maintaining solid investment grade credit ratings

In conjunction with these goals, PNM and TNMP are dedicated to:


•	Maintaining strong plant performance, system reliability, and employee safety


•	Delivering a superior customer experience


•	Environmental leadership in their business operations


•	Supporting the communities in their service territories

Earning Authorized Returns on Regulated Businesses

PNMR’s success in accomplishing its strategic goals is highly dependent on continued favorable regulatory treatment for its utilities and their strong operating performance. The Company has multiple strategies to achieve favorable regulatory treatment, all of which have as their foundation a focus on the basics: safety, operational excellence, and customer satisfaction, while engaging stakeholders to build productive relationships. Both PNM and TNMP seek cost recovery for their investments through general rate cases and various rate riders.

PNM filed a general rate case with the NMPRC in December 2014. PNM’s application proposed a revenue increase of $107.4 million, effective January 1, 2016, based on a calendar 2016 future test year (“FTY”) and a ROE of 10.5%. On April 17, 2015, the Hearing Examiner in the case issued an Initial Recommended Decision to the NMPRC recommending that the NMPRC find PNM’s application incomplete, primarily due to procedural defects, and reject it. PNM disagreed with the Hearing Examiner’s Initial Recommended Decision and filed exceptions. On May 13, 2015, the NMPRC voted to accept the Initial Recommended Decision and dismissed PNM’s application.

On August 29, 2015, PNM filed a new application with the NMPRC for a general increase in retail electric rates. The application proposes a revenue increase of $123.5 million, including base fuel revenues. The application is based on a FTY beginning October 1, 2015, which meets the NMPRC’s interpretation of the FTY statute discussed below, and a ROE of 10.5%. The primary drivers of PNM’s identified revenue deficiency are infrastructure investments and declines in forecasted energy sales as a result of PNM’s successful energy efficiency programs and other economic factors. The new application includes several proposed changes to rate design to establish fair and equitable pricing across rate classes and to better align cost recovery with cost causation. Specific rate design proposals include increased customer and demand charges, a revenue decoupling pilot program

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applicable to residential and small power customers, a re-allocation of revenue among PNM’s customer classes, a new economic development rate, and continuation of PNM’s renewable energy rider. New rates are expected to become effective in the third quarter of 2016.

On May 27, 2015, the NMPRC approved an order that defines a FTY as a period that begins no later than 45 days following the filing of an application to increase rates. PNM disagrees with the interpretation adopted by the NMPRC and believes that the correct interpretation of the New Mexico FTY statute allows a FTY to begin up to 13 months after the filing of an application. On June 25, 2015, PNM filed a Notice of Appeal to the NMSC, challenging the NMPRC’s order. There is no required timeframe for the NMSC to act on PNM’s appeal. Several other utilities have filed separate notices of appeals with the NMSC and one party to PNM’s rate case filed a notice of cross appeal. The NMPRC has requested that the NMSC remand the matter back to the NMPRC in order to conduct a rulemaking process on the definition and parameters of a FTY for rate cases. PNM and the NMPRC filed a joint motion for a temporary 30-day stay and remand of PNM’s appeal so that the NMPRC can reconsider its FTY order in PNM’s 2014 rate case. The NMSC has not acted on the pending motions.

The PUCT has approved mechanisms that allow TNMP to recover capital invested in transmission and distribution projects without having to file a general rate case, which allows for more timely recovery. The NMPRC has approved rate riders for renewable energy and energy efficiency that allow for more timely recovery of investments and improve the ability to earn authorized returns from PNM’s retail customers.

In early 2013, PNM completed rate proceedings for all of its FERC regulated transmission customers and for NEC, its largest generation services customer, which improved PNM’s returns for providing those services. PNM has allocated a portion of its generation assets to serve FERC wholesale generation services customers for a number of years. Recently, the low natural gas price environment has caused market prices for power to be substantially lower than what PNM is able to offer customers under the cost of service model that FERC requires PNM to use. As a result of this change in market conditions, PNM has not been earning an adequate return on the assets required to serve wholesale contracts and has decided to stop pursuing wholesale contracts that are served with the same generation assets that serve retail customers.

PNM had a PSA to supply power to NEC through 2035, which was approved by FERC in April 2013. On April 8, 2015, NEC filed a petition for a declaratory order requesting that FERC find that NEC can purchase an unlimited amount of power and energy from third party supplier(s) under the PSA. PNM intervened, requesting that FERC deny NEC’s petition. On July 16, 2015, FERC set the matter for a public hearing concerning the parties’ intent with regard to certain provisions of the PSA and held the hearing in abeyance to provide time for settlement judge procedures. In 2014, monthly billing demand for power supplied to NEC averaged approximately 55 MW and revenues were $28.4 million under the PSA.

On October 29, 2015, PNM and NEC entered into, and filed with FERC, a settlement agreement that includes amendments to the PSA and related contracts, subject to FERC approval. Under the agreement, PNM would continue to serve all of NEC’s load through December 31, 2015 at rates that are substantially consistent with those currently provided under the PSA. In 2016, PNM would serve all of NEC’s load at reduced demand and energy rates from those under the PSA. Beginning January 1, 2016, NEC would also pay certain third-party transmission costs that it did not pay in 2014. The PSA would terminate on December 31, 2016. In 2017, PNM would continue to serve 10 MW of NEC’s load under a short-term coordination tariff at a rate lower than provided under the PSA, but higher than prices currently available under short-term market rates. Although the settlement agreement will negatively impact results of operations in 2016 and 2017, PNM expects to be able to mitigate these impacts through market sales of power that would have been sold to NEC, reductions in fuel and transmission expenses, and other measures. PNM anticipates that, in future general rate cases, assets and costs previously assigned to serve NEC will be reassigned, primarily to retail customers. PNM is unable to predict if FERC will approve the settlement.

On June 29, 2014, the contract to provide power to Gallup, previously PNM’s second largest customer for wholesale generation services expired. PNM’s general rate case application discussed above includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup.

PNM currently has a pending case before FERC in which it is requesting an increase in rates charged to transmission customers based on a formula rate mechanism. On March 20, 2015, PNM along with five other parties entered into a settlement agreement, which was filed at FERC. The settlement reflects a ROE of 10% and results in an annual increase of $1.3 million above the rates approved in the previous rate case. There is no required time frame for FERC to act upon the settlement.

Currently, PNM’s 134 MW interest in PVNGS Unit 3 is excluded from NMPRC jurisdictional rates. The power generated

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from that interest is sold into the wholesale market and any earnings or losses are realized by shareholders. As part of compliance with the requirements for BART at SJGS discussed below, PNM has requested NMPRC approval to include PVNGS Unit 3 as a jurisdictional resource in the determination of rates charged to customers in New Mexico beginning in 2018.

Fair and timely rate treatment from regulators is crucial to PNM and TNMP earning their allowed returns, which is critical for PNMR’s ability to achieve its strategic goals. PNMR believes that if the utilities earn their allowed returns, it would be viewed positively by credit rating agencies and would further improve the Company’s ratings, which could lower costs to utility customers. Also, earning allowed returns should result in increased earnings for PNMR, which would lead to increased growth in ongoing EPS.

Additional information about rate filings is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and in Note 12.

Delivering Above Industry-Average Earnings and Dividend Growth

PNMR’s strategic goal to deliver above industry-average earnings and dividend growth enables investors to realize the value in the Company’s business. PNMR’s current target is seven to nine percent earnings growth through 2019. Earnings growth is based on ongoing earnings, which is a non-GAAP financial measure that excludes certain non-recurring, infrequent, and other items from earnings determined in accordance with GAAP.

PNMR targets a dividend payout ratio of 50% to 60% of its ongoing earnings. The annual common stock dividend was raised by 16% in February 2012, 14% in February 2013, 12% in December 2013, and 8% in December 2014. PNMR expects to provide above-average dividend growth in the near-term and to manage the payout ratio to meet its long-term target. The Board will continue to evaluate the dividend on an annual basis, considering sustainability and growth, capital planning, and industry standards.

Maintaining Investment Grade Credit Ratings

PNM is committed to maintaining investment grade credit ratings. See the subheading Liquidity included in the full discussion of Liquidity and Capital Resources below for the specific credit ratings for PNMR, PNM, and TNMP. Currently, all of the credit ratings issued by both Moody’s and S&P on the Company’s debt are investment grade.

Business Focus

PNMR strives to create enduring value for customers, communities, and stockholders. PNMR’s strategy and decision-making are focused on safely providing reliable, affordable, and environmentally responsible power. PNMR works closely with customers, stakeholders, legislators, and regulators to ensure that resource plans and infrastructure investments benefit from robust public dialogue and balance the diverse needs of our communities.

Reliable and Affordable Power

PNMR and its utilities are aware of the important roles they play in enhancing economic vitality in their New Mexico and Texas service territories. Management believes that maintaining strong and modern electric infrastructure is critical to ensuring reliability and economic growth. When considering expanding or relocating to other communities, businesses consider energy affordability and reliability to be important factors. PNM and TNMP strive to balance service affordability with infrastructure investment to maintain a high level of electric reliability and to deliver a superior customer experience. The utilities also work to ensure that rates reflect actual costs of providing service.

Investing in PNM’s and TNMP’s infrastructure is critical to ensuring reliability and meeting future energy needs. Both utilities have long-established records of providing customers with reliable electric service. For three out of the last five years, both PNM and TNMP have ranked in the top quartile nationally for reliability. In 2014, PNM delivered its best reliability performance in the past seven years and TNMP’s reliability was its best in a decade.

In September 2011, TNMP began its deployment of advanced meters for homes and businesses across its Texas service area. Through September 30, 2015 , TNMP had completed installation of more than 210,000 advanced meters, which is approximately 87% of the anticipated total. TNMP’s deployment is expected to be completed in 2016.

As part of the State of Texas’ long-term initiative to create an advanced electric grid, installation of advanced meters will ultimately give consumers more data about their energy consumption and help them make more informed decisions. In addition,

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TNMP is installing a new outage management system that will leverage capabilities of the advanced metering infrastructure to enhance TNMP’s responsiveness to outages.

During the 2012 to 2014 period, PNM and TNMP together invested $1,062.8 million in utility plant, including substations, power plants, nuclear fuel, and transmission and distribution systems. In 2012, PNM announced plans for the 40 MW natural gas-fired La Luz peaking generating station to be located near Belen, New Mexico. Construction began in April 2015 and the facility is expected to go into service in late 2015.

NMPRC rules require that investor owned utilities file an IRP every three years. The IRP is required to cover a 20 -year planning period and contain an action plan covering the first four years of that period. PNM filed its 2014 IRP on July 1, 2014. The four-year action plan was consistent with the replacement resources identified in PNM’s application to retire SJGS Units 2 and 3. PNM indicated that it planned to meet its anticipated energy demand with a combination of additional renewable energy resources, energy efficiency, and natural gas-fired facilities.

Environmentally Responsible Power

PNMR has a long-standing record of environmental stewardship. PNM’s environmental focus has been in three key areas:


•	Developing strategies to meet regional haze rules at the coal-fired SJGS as cost-effectively as possible while providing broad environmental benefits that also demonstrate progress in addressing new federal regulations for CO ₂ emissions from existing power plants


•	Preparing to meet New Mexico’s increasing renewable energy requirements as cost-effectively as possible

• Increasing energy efficiency participation

Another area of emphasis is the reduction of the amount of fresh water used during electricity generation at PNM’s power plants. The fresh water used per MWh generated has dropped by 25% since 2002, primarily due to the growth of renewable energy sources, the expansion of Afton to a combined-cycle plant that has both air and water cooling systems, and the use of gray water for cooling at Luna. As discussed below, PNM has requested approval to shut down SJGS Units 2 and 3, which would reduce water consumption at that plant by about 50%. In addition to the above areas of focus, the Company is working to reduce the amount of solid waste going to landfills through increased recycling and reduction of waste. The Company has performed well in this area in the past and expects to continue to do so in the future.

Renewable Energy

PNM’s renewable procurement strategy includes utility-owned solar capacity, as well as wind and geothermal energy purchased under PPAs. As of January 1, 2015, PNM had 67 MW of utility-owned solar capacity, including 23 MW completed in 2014. PNM is currently constructing an additional 40 MW of PNM-owned solar PV facilities, which are contemplated in PNM’s application to retire SJGS Units 2 and 3 discussed below. The application for a general rate increase discussed above includes recovery of the costs associated with the new 40 MW solar facilities. In addition, PNM purchases power from a customer-owned distributed solar generation program that had an installed capacity of 43 MW at September 30, 2015. PNM also owns the 500 KW PNM Prosperity Energy Storage Project, which uses advanced batteries to store solar power and dispatch the energy either during high-use periods or when solar production is limited. The project features one of the largest combinations of battery storage and PV energy in the nation and involves extensive research and development of advanced grid concepts. The facility was the nation’s first solar storage facility fully integrated into a utility’s power grid.

Since 2003, PNM has purchased the output from a 204 MW wind facility and began purchasing the output of another existing 102 MW wind energy center on January 1, 2015. PNM has a 20-year agreement to purchase energy from a geothermal facility built near Lordsburg, New Mexico. The facility began providing power to PNM in January 2014. The current capacity of the facility is 3 MW and future expansion may result in up to 10 MW of generation capacity. PNM also purchases RECs to meet the RPS.

These renewable resources are key means for PNM to meet the RPS and related regulations, which require PNM to achieve prescribed levels of energy sales from renewable sources, if that can be accomplished without exceeding the RCT limit set by the NMPRC. PNM makes renewable procurements consistent with the plans approved by the NMPRC. PNM’s 2015 renewable energy procurement plan meets RPS and diversity requirements within the RCT in 2015 and 2016. PNM will continue to procure renewable resources while balancing the impact to customers’ bills in order to meet New Mexico’s escalating RPS requirements.

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SJGS

PNM continues its efforts to comply with the EPA regional haze rule in a manner that minimizes the cost impact to customers while still achieving broad environmental benefits. Additional information about BART at SJGS is contained in Note 16 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and in Note 11.

In August 2011, EPA issued a FIP for regional haze that would have required the installation of SCRs on all four units at SJGS by September 2016. However, PNM, NMED, and EPA agreed on February 15, 2013 to pursue a revised plan that could provide a new BART path to comply with federal visibility rules at SJGS. The terms of the non-binding agreement would result in the retirement of SJGS Units 2 and 3 by the end of 2017 and the installation of SNCRs on Units 1 and 4 by early 2016. A RSIP was approved by the EIB and EPA. PNM anticipates installation of SNCRs and related BDT equipment will be completed within the timeframe contained in the RSIP.

The RSIP would achieve similar visibility improvements as the installation of SCRs on all four units at SJGS at a lower cost to PNM customers. It has the added advantage of reducing other emissions beyond NOx, including SO ₂ , particulate matter, CO ₂ , and mercury, as well as reducing water usage.

In December 2013, PNM made a filing with the NMPRC requesting certain approvals necessary to effectuate the RSIP. On October 1, 2014, PNM filed a proposed stipulation to settle this case. A public hearing in the NMPRC case was held in January 2015. On April 8, 2015, the Hearing Examiner in the case issued a Certification of Stipulation, which recommends that the NMPRC reject the stipulation as proposed. PNM filed exceptions to the certification. Except as noted below, the NMPRC has not acted on the stipulation or certification.

In June 2015, the NMPRC designated a facilitator to determine whether an uncontested settlement among some or all of the parties in this case could be accomplished. On August 13, 2015, as a result of the facilitation process, a settlement agreement was filed with the NMPRC. In addition to PNM, the staff of the NMPRC, the NMAG, Western Resource Advocates, the Coalition for Clean Affordable Energy, NMIEC, Interwest Energy Alliance, and New Mexico Independent Power Producers support the settlement agreement. NEE opposes the settlement agreement. The stipulating parties agreed that the October 2014 stipulation should be approved, as modified by the settlement agreement (collectively, the “Stipulated Settlement”). Under the terms of the Stipulated Settlement, if approved by the NMPRC, PNM would:


•	Retire SJGS Units 2 and 3 (PNM’s current ownership interest totals 418 MW) at December 31, 2017 and recover, over 20 years, 50% (estimated to be approximately $128.5 million) of their undepreciated net book value at that date and earn a regulated return on those costs


•	Be granted a CCN for 132 MW in SJGS Unit 4, with an initial book value of zero, plus SNCR costs and whatever portion of BDT costs the NMPRC determines to be reasonable and prudent to be allowed for recovery in rates


•	Be granted a CCN for 134 MW of PVNGS Unit 3 with an initial rate base value equal to the book value as of December 31, 2017 (estimated to be approximately $150 million)


•	Be authorized to acquire 65 MW of SJGS Unit 4 as merchant utility plant, which would not be included in rates charged to retail customers


•	Accelerate recovery of SNCR costs on SJGS Units 1 and 4 so that the costs are fully recovered by July 1, 2022 (cost recovery for PNM’s BDT project on those units will be determined in PNM’s next general rate case)


•	Make a NMPRC filing in 2018 to determine the extent that SJGS should continue serving PNM’s customers’ needs after mid-2022


•	Retire one MWh of RECs that include a zero-CO ₂ emission attribute compliant with EPA’s Clean Power Plan beginning January 1, 2020 for every MWh produced by 197 MW of coal-fired generation from SJGS Unit 4 (the cost of these RECs would be capped at $7.0 million per year and recovered in rates)


•	Not recover approximately $20 million of increased operations and maintenance expenses and other costs incurred in connection with CAA compliance

If the NMPRC issues an order that modifies the Stipulated Settlement, any stipulating party can void it. Although NEE filed a petition at the NMSC requesting four of the five NMPRC commissioners be recused from this case and to stay the proceedings, the NMSC issued orders that allowed the hearing to be conducted by the Hearing Examiner, but ordered that any final action by the NMPRC be stayed, pending a decision by the NMSC on the petition. A hearing was held from October 13, 2015 through October 20, 2015. Oral argument on the NEE’s petition is scheduled for November 9, 2015 before the NMSC. PNM is unable to predict the outcome of the NMSC proceeding, whether NMPRC and other required approvals will be obtained and other conditions satisfied in order for the agreements discussed above to become effective and restructuring consummated, whether any

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party will void the Supplemental Stipulation, or the ultimate outcome of this matter. If the NMPRC were to issue an order adopting all of the provisions of the Stipulated Settlement, PNM estimates it would incur a pre-tax regulatory disallowance between $145 million and $155 million.

In connection with the implementation of the RSIP and the proposed retirement of SJGS Units 2 and 3, some of the SJGS participants expressed a desire to exit their ownership in the plant. As a result, the SJGS participants began negotiating a restructuring of the ownership in SJGS, as well as addressing the obligations of the exiting participants for plant decommissioning, mine reclamation, environmental matters, and certain future operating costs, among other items.

In June 2014, non-binding arrangements were reached among the SJGS owners that identified the participants who would be exiting active participation in SJGS effective December 31, 2017 and participants, including PNM, who would retain an interest in the ongoing operation of one or more units of SJGS. These arrangements provided the essential terms of restructured ownership of SJGS. These arrangements recognized the need to have greater certainty in regard to the economic cost and availability of fuel for SJGS for the period after December 31, 2017. See Coal Supply in Note 11. On January 7, 2015, one of the participants in SJGS Unit 4 notified the other participants that it will not acquire additional MWs in Unit 4, leaving 65 MWs unsubscribed in that unit. Although PNM indicated that it would not acquire any of the unsubscribed MWs, PNMR indicated that PNMR Development would acquire the 65 MWs.

In May 2015, PNMR, PNM, PNMR Development, and the California owners of SJGS Unit 4 entered into an agreement, which provides PNM and PNMR Development options to acquire 132 MW and 65 MW of the Unit 4 capacity currently owned by the California entities in exchange for PNM and PNMR Development funding the capital improvements related to Unit 4 effective as of January 1, 2015. PNMR’s current projection of capital expenditures includes those related to the 65 MW.

On May 27, 2015, the NMPRC issued an order requiring PNM to file executed restructuring and coal supply agreements by July 1, 2015, which was subsequently extended to August 1, 2015. On July 1, 2015, PNM filed the executed coal supply and related agreements with the NMPRC. On July 31, 2015, PNM filed fully executed restructuring agreements.

The San Juan Project Restructuring Agreement (“RA”) sets forth the agreement among the SJGS owners regarding ownership restructuring and contains many of the provisions of the June 2014 arrangements. On December 31, 2017, PNM would acquire 132 MW of the capacity in SJGS Unit 4 from the California owners and PNMR Development would acquire 65 MW of such capacity. Effectiveness of the RA is dependent on approvals by NMPRC and FERC, as well as the effectiveness of a new coal supply agreement (“CSA”) for SJGS. Effectiveness of the CSA is dependent upon the closing of the purchase of SJCC mining operation by the new third-party miner. It is currently anticipated that the CSA and the RA will become effective contemporaneously on January 1, 2016. Under the RA, PNM would acquire the coal inventory of the exiting SJGS participants on January 1, 2016 and provide coal supply to the exiting participants during the period from January 1, 2016 through December 31, 2017, which arrangement PNM believes will provide economic benefits to PNM. PNM anticipates that coal costs under the CSA will be significantly less than under the current arrangement. Since substantially all coal costs are passed through PNM’s FPPAC, the benefit of the reduced costs and the economic benefits of the coal inventory arrangement with the exiting owners will be passed through to PNM’s customers.

PNM, as the SJGS operating agent, presented the SNCR project to the participants in Unit 1 and Unit 4 for approval in late October 2013. The project was approved for Unit 1, but the Unit 4 project did not obtain the required percentage of votes for approval. Other capital projects related to Unit 4 also were not approved by the participants. PNM is authorized and obligated under the SJPPA to take reasonable and prudent actions necessary for the successful and proper operation of SJGS pending resolution by the participants. Accordingly, PNM has requested that the owners of Unit 4 approve expenditures critical to being able to comply with the time frame in the RSIP with respect to Unit 4 project. The Unit 4 owners did not approve the requests. Therefore, PNM issued several “Prudent Utility Practice” notices that, under the SJPPA, PNM was continuing certain critical activities to keep the Unit 4 project on schedule.

In addition to the regional haze rule, SJGS is required to comply with other rules currently being developed or implemented that affect coal-fired generating units, including recent rules regarding GHG under Section 111(d) of the CAA. Because of environmental upgrades completed in 2009, SJGS is well positioned to outperform the mercury limit imposed by EPA in the 2011 Mercury and Air Toxics Standards. The major environmental upgrades on each of the four units at SJGS have significantly reduced emissions of NOx, SO ₂ , particulate matter, and mercury. Since 2006, SJGS has reduced NOx emissions by 42%, SO ₂ by 67%, particulate matter by 71%, and mercury by 95%.

Energy Efficiency

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Energy efficiency also plays a significant role in helping to keep customers' electricity costs low while continuing to meet their energy needs. PNM’s and TNMP’s energy efficiency and load management portfolios continue to achieve robust results. In 2014, annual energy saved as a result of PNM’s portfolio of energy efficiency programs was approximately 70 GWh. This is equivalent to the annual consumption of approximately 9,700 homes in PNM’s service territory. PNM’s load management and energy efficiency programs also help lower peak demand requirements. TNMP’s energy efficiency programs in 2014 resulted in energy savings totaling an estimated 17 GWh. This is equivalent to the annual consumption of approximately 1,600 homes in TNMP’s service territory.

Creating Value for Customers and Communities

The Company strives to deliver a superior customer experience by understanding the dynamic needs of its customers through ongoing market research, identifying and establishing best-in-class services and programs, and proactively communicating and engaging with customers at a regional and community level. Beginning in 2013, PNM refocused its efforts to improve the customer experience through an integrated marketing and communications strategy that encompassed brand repositioning and advertising, customer service improvements, including billing and payment options, and strategic customer and stakeholder engagement.

Recognizing the importance of environmental stewardship to customers and other stakeholders, PNM expanded engagement with environmental stakeholders to promote ongoing dialogue and input. Similarly, PNM proactively communicated with communities about its efforts and plans related to environmental stewardship. Customers took note of PNM’s efforts in this area. A nationally recognized customer satisfaction benchmark revealed gains in awareness of PNM’s efforts to improve environmental impact, as well as customer perceptions around the commitment to preserving the environment now and for future generations.

PNM continues to expand its environmental stakeholder outreach, piloting small environmental stakeholder dialogue groups on key issues such as renewable energy and energy efficiency planning. PNM also employed proactive stakeholder outreach in two key projects – the development of PNM’s renewable energy procurement plans that involved distributed solar energy developers early in the conversation and the siting of the gas-fired La Luz peaking generation facility near Belen, New Mexico, which featured in-depth community involvement and education early in the planning stages of the project. In both cases, highly favorable outcomes were achieved and potentially controversial negative media coverage was avoided.

PNM expanded its integrated communication efforts with the launch of a new customer information website focused on PNM’s major regulatory filings, including BART at SJGS and PNM’s general rate case. The website, www.PowerforProgress.com , provides the details of current requests, as well as the background on PNM’s efforts to maintain reliability, keep prices affordable, and protect the environment. The website is designed to be a resource for the facts about PNM's operations and community support efforts, including plans for building a sustainable energy future for New Mexico.

Through outreach, collaboration, and various community-oriented programs, PNMR has a demonstrated commitment to build productive relationships with stakeholders, including customers, regulators, legislators, and intervenors.

Building off work that began in 2008, PNM has continued outreach efforts to connect low-income customers with nonprofit community service providers offering support and help with such needs as utility bills, food, clothing, medical programs, services for seniors, and weatherization. In 2014, PNM hosted 31 community events throughout its service territory to assist low-income customers. Furthermore, the PNM Good Neighbor Fund provided $0.3 million of assistance with utility bills to 3,153 families in 2014. In 2014, PNM committed funding of $0.4 million to the PNM Good Neighbor Fund.

The PNM Resources Foundation helps nonprofits become more energy efficient through Reduce Your Use grants. In 2013, PNMR committed funding of $3.5 million to the PNM Resources Foundation. For 2014, the foundation awarded $0.2 million to support 54 projects in New Mexico to provide shade structure installations, window replacements, and efficient appliance purchases. Since the program’s inception in 2008, Reduce Your Use grants have provided nonprofit agencies in New Mexico with a total of $1.6 million of support. In 2014, the PNM Resources Foundation launched a new grant program designed to help nonprofit organizations build more vibrant communities. Power Up Grants in the aggregate amount of $0.5 million were awarded to 24 nonprofits in New Mexico and Texas for projects ranging from creating community gathering spaces to revitalizing neighborhood parks to building a youth sports field.

In Texas, community outreach is centered first on local relationships, specifically with community leaders, nonprofit organizations and key customers in areas served by TNMP. Community liaisons serve in each of TNMP's three geographic business areas, reaching out and ensuring productive lines of communication between TNMP and its customer base.

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TNMP maintains long-standing relationships with several key nonprofit organizations, including agencies that support children and families in crisis, food banks, environmental organizations, and educational nonprofits, through employee volunteerism and corporate support. TNMP also actively participates in safety fairs and demonstrations in addition to supporting local chambers of commerce in efforts to build their local economies.

TNMP's energy efficiency program provides unique offers to multiple customer groups, including residential, commercial, government, education, and nonprofit customers. These programs not only enable peak load and consumption reductions, particularly important when extreme weather affects Texas' electric system, but also demonstrate TNMP's commitment to more than just delivering electricity by partnering with customers to optimize their energy usage.

Economic Factors

In the nine months ended September 30, 2015 , PNM experienced a decrease in weather normalized retail load of 1.4% compared to 2014. There continue to be signs that New Mexico’s economy is stabilizing. However, economic growth continues to be slow and the economic data provides conflicting indicators. Job growth in Albuquerque has increased, but is still below the national average. Housing prices in New Mexico increased in the first quarter of 2015 compared to the first quarter of 2014. In the nine months ended September 30, 2015 , TNMP’s weather normalized retail load increased 2.7% compared to 2014. Since the recent recession, Texas has fared better than the national average in job growth and unemployment. However, there has been some recent softening in job growth, particularly in the Houston area that appears to be related to lower oil prices. However, employment growth is a stronger predictor of load. Texas’ employment growth rates are well above the national rate, while New Mexico’s employment is showing modest growth.

Results of Operations

A summary of net earnings attributable to PNMR is as follows:



	Three Months Ended September 30,							Nine Months Ended September 30,
	2015		2014		Change			2015		2014		Change
	(In millions, except per share amounts)
Net earnings attributable to PNMR	$	61.0	$	55.7	$	5.4		$	107.1	$	97.3	$	9.8
Average diluted common and common equivalent shares	80.1		80.2		(0.1		)	80.1		80.3		(0.2		)
Net earnings attributable to PNMR per diluted share	$	0.76	$	0.69	$	0.07		$	1.34	$	1.21	$	0.13

The components of the change in earnings attributable to PNMR are:



	Three Months Ended		Nine Months Ended
	September 30, 2015		September 30, 2015
	(In millions)
PNM	$	4.0	$	7.6
TNMP	1.3		4.5
Corporate and Other	—		(2.4		)
Net change	$	5.4	$	9.8

PNMR’s operational results were affected by the following:


•	Lower retail load at PNM partially offset by higher retail load at TNMP


•	Warmer weather in three months ended September 30, 2015, partially offset by milder weather in the first six months of 2015


•	Rate increases for PNM and TNMP – additional information about these rate increases is provided in Note 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 12


•	Reduced rent payments upon renewal of leases for PVNGS Unit 1


•	A refund of amounts previously paid under the FERC tariff for gas transportation agreements

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•	Net unrealized gains and losses on mark-to-market economic hedges for sales and fuel costs not recoverable under PNM’s FPPAC


•	Fluctuations in prices for sales of power from PVNGS Unit 3


•	Other factors impacting results of operation for each segment are discussed under Results of Operations below

Liquidity and Capital Resources

The Company has revolving credit facilities that provide capacities for short-term borrowing and letters of credit of $300.0 million for PNMR and $400.0 million for PNM, both of which have been extended to expire in October 2020. In addition, PNM has a $50.0 million revolving credit facility, which expires in January 2018, with banks having a significant presence in New Mexico and TNMP has a $75.0 million revolving credit facility, which expires in September 2018. Total availability for PNMR on a consolidated basis was $795.5 million at October 23, 2015 . The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. PNMR also has intercompany loan agreements with each of its subsidiaries.

The Company projects that its total capital requirements, consisting of construction expenditures and dividends, will total $2,603.8 million for 2015-2019, including amounts expended through September 30, 2015 . The construction expenditures include estimated amounts related to environmental upgrades at SJGS to address regional haze and the identified sources of replacement capacity under the revised plan for compliance described in Note 11. The construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, peaking resources needed to meet needs outlined in PNM’s current IRP, environmental upgrades at Four Corners, the purchase of the leased portion of the EIP, and the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases. In addition to internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing in the form of debt refinancing, new debt issuances, and/or new equity in order to fund its capital requirements during the 2015-2019 period. The Company currently believes that its internal cash generation, existing credit arrangements, and access to public and private capital markets will provide sufficient resources to meet the Company’s capital requirements.

RESULTS OF OPERATIONS

Segment Information

The following discussion is based on the segment methodology that PNMR’s management uses for making operating decisions and assessing performance of its various business activities. See Note 3 for more information on PNMR’s operating segments.

The following discussion and analysis should be read in conjunction with the Condensed Consolidated Financial Statements and Notes thereto. Trends and contingencies of a material nature are discussed to the extent known. Refer also to Disclosure Regarding Forward Looking Statements and to Part II, Item 1A. Risk Factors.

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PNM

The following table summarizes the operating results for PNM:



	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Electric operating revenues	$	333.4		$	335.0		$	(1.6	)	$	870.8		$	873.4		$	(2.6	)
Cost of energy	105.7			115.1			(9.4		)	299.3			304.4			(5.1		)
Margin	227.7			219.9			7.8			571.5			569.1			2.4
Operating expenses	105.0			101.8			3.2			312.5			315.7			(3.2		)
Depreciation and amortization	29.0			27.5			1.5			86.4			81.6			4.8
Operating income	93.7			90.6			3.1			172.5			171.7			0.8
Other income (deductions)	6.4			3.7			2.7			23.4			15.0			8.4
Net interest charges	(19.8		)	(20.1		)	0.3			(59.5		)	(59.9		)	0.4
Segment earnings before income taxes	80.3			74.2			6.1			136.5			126.8			9.7
Income (taxes)	(27.3		)	(25.1		)	(2.2		)	(44.6		)	(42.3		)	(2.2		)
Valencia non-controlling interest	(3.7		)	(3.7		)	—			(10.9		)	(11.1		)	0.2
Preferred stock dividend requirements	(0.1		)	(0.1		)	—			(0.4		)	(0.4		)	—
Segment earnings	$	49.2		$	45.2		$	4.0		$	80.6		$	73.0		$	7.6

The following table summarizes the significant changes to electric operating revenues, cost of energy, and margin:



	2014/2015 Change
	Three Months Ended September 30,									Nine Months Ended September 30,
	Electric									Electric
	Operating			Cost of						Operating			Cost of
	Revenues			Energy			Margin			Revenues			Energy			Margin
	(In millions)
Customer usage/load	$	(3.3	)	$	—		$	(3.3	)	$	(6.7	)	$	—		$	(6.7	)
Weather	4.2			—			4.2			0.2			—			0.2
Transmission	(1.2		)	(0.1		)	(1.1		)	(3.4		)	(0.1		)	(3.3		)
FPPAC	(4.1		)	(4.1		)	—			18.2			18.2			—
Economy energy service	(0.7		)	(0.7		)	—			(3.5		)	(3.4		)	(0.1		)
Rio Bravo purchase	—			(0.3		)	0.3			—			(3.6		)	3.6
Unregulated margin	(0.2		)	(0.3		)	0.1			(0.8		)	(0.7		)	(0.1		)
Wholesale contracts	(0.5		)	(0.5		)	—			(5.5		)	(2.1		)	(3.4		)
Energy efficiency rider	0.8			—			0.8			1.2			—			1.2
Renewable energy rider	2.7			0.6			2.1			5.5			1.6			3.9
Net unrealized economic hedges	1.5			(0.1		)	1.6			(1.1		)	0.2			(1.3		)
Non-FPPAC off-system activity	(2.1		)	(1.4		)	(0.7		)	(6.4		)	(6.1		)	(0.3		)
El Paso Natural Gas refund	—			—			—			—			(4.2		)	4.2
Other	1.3			(2.5		)	3.8			(0.3		)	(4.9		)	4.5
Net change	$	(1.6	)	$	(9.4	)	$	7.8		$	(2.6	)	$	(5.1	)	$	2.4

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The following table shows electric operating revenues by customer class and average number of customers:



	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions, except customers)
Residential	$	131.0		$	127.2		$	3.8		$	331.8		$	317.6		$	14.2
Commercial	128.1			127.7			0.4			338.8			326.6			12.2
Industrial	21.3			21.3			—			57.2			54.4			2.8
Public authority	8.0			8.0			—			19.8			19.2			0.6
Economy service	8.7			9.3			(0.6		)	26.5			29.9			(3.4		)
Other retail	(0.6		)	(1.2		)	0.6			3.5			4.0			(0.5		)
Transmission	8.4			9.5			(1.1		)	24.9			28.3			(3.4		)
Firm-requirements wholesale	7.4			8.1			(0.7		)	22.9			30.0			(7.1		)
Other sales for resale	16.4			21.9			(5.5		)	46.7			63.5			(16.8		)
Mark-to-market activity	4.7			3.2			1.5			(1.3		)	(0.1		)	(1.2		)
	$	333.4		$	335.0		$	(1.6	)	$	870.8		$	873.4		$	(2.6	)
Average retail customers (thousands)	515.3			511.4			3.9			514.4			510.9			3.5

The following table shows GWh sales by customer class:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015	2014	Change		2015	2014	Change
	(Gigawatt hours)
Residential	958.0	936.1	21.9		2,436.7	2,442.2	(5.5	)
Commercial	1,060.1	1,069.5	(9.4	)	2,882.2	2,942.7	(60.5	)
Industrial	254.7	254.6	0.1		720.3	737.2	(16.9	)
Public authority	72.8	74.3	(1.5	)	182.7	189.0	(6.3	)
Economy service	195.8	188.8	7.0		591.8	572.4	19.4
Firm-requirements wholesale	108.3	105.7	2.6		322.9	415.9	(93.0	)
Other sales for resale	515.8	602.0	(86.2	)	1,527.4	1,725.0	(197.6	)
	3,165.5	3,231.0	(65.5	)	8,664.0	9,024.4	(360.4	)

During 2015, PNM continued to be impacted by a sluggish economy in New Mexico. In particular, the Albuquerque metropolitan area has lagged the nation in economic recovery. However, there continue to be signs that New Mexico’s economy is stabilizing. The rolling twelve-month average job growth in Albuquerque is currently at 1.4%, with several local businesses making announcements of new jobs, although the national average is 2.0%. New Mexico housing prices increased 1.5% in the first quarter of 2015 compared to the first quarter of 2014. Overall economic growth continues to be slow. However, PNM experienced an increase in the average number of retail customers of 0.8% and 0.7% for the three and nine months ended September 30, 2015 compared to 2014. PNM’s weather normalized retail KWh sales were 1.7% and 1.4% lower for the three and nine months ended September 30, 2015 compared to 2014, which decreased revenues and margin $3.3 million and $6.7 million in 2015 compared to 2014. Warmer weather in the third quarter of 2015 compared to 2014 increased revenues and margin $4.2 million for the three months ended September 30, 2015. This was partially offset by milder weather in the first two quarters of 2015 compared to 2014, resulting in increased revenues and margin of $0.2 million for the nine months ended September 30, 2015. For the three months ended September 30, 2015, cooling degree days were 14.5% higher than in 2014. For the nine months ended September 30, 2015 compared to 2014 heating degree days were 0.6% lower and cooling degree days were higher 3.1%. Cooling degree days only have a minor impact on the first quarter of any year, whereas heating degree days only have a minor impact on the second and third quarters.

For the three and nine months ended September 30, 2015, transmission revenues decreased $1.2 million and $3.4 million and margin decreased $1.1 million and $3.3 million compared to 2014. These decreases primarily resulted from the expiration

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of long-term point-to-point contracts aggregating $0.7 million and $2.5 million for the three and nine months ended September 30, 2015 compared to 2014. Lower short-term point-to-point transmission revenues decreased revenues and margin $0.5 million and $1.2 million for the three and nine months ended September 30, 2015 compared to 2014. The decreases were partially offset by a May 2014 rate increase under PNM’s formula-based transmission rate case, which increased revenues $0.2 million and $0.7 million during the three and nine months ended September 30, 2015.

In April 2014, the NMPRC approved the continuation of PNM’s FPPAC and authorized PNM to recover the remaining under-collected balance in its FPPAC balancing account over 18 months effective July 1, 2014. As a result of quarterly changes in the rate charged under the rider, PNM’s revenues increased in nine months ended September 30, 2015 but decreased in the three months ended September 30, 2015 compared to 2014. These changes in revenue were offset in cost of energy with no impact on margin.

PNM provides economy energy services to a major customer. Under this contract, PNM purchases energy on the customer’s behalf and delivers the energy to the customer’s location through PNM’s transmission system. PNM charges the customer for the cost of the energy as a direct pass through to the customer with no impact to margin. Although revenue from this customer decreased for the three and nine months ended September 30, 2015 compared to 2014, there is only a minor impact on margin, which results from providing ancillary services.

PNM closed on the acquisition of Rio Bravo, formerly known as Delta, on July 17, 2014. Prior to acquiring Rio Bravo, PNM had a 20 year PPA covering all of the output of the facility. PNM accounted for the PPA as an operating lease and recorded fixed and variable costs in cost of energy. As a result of the Rio Bravo acquisition, cost of energy decreased and margin increased $0.3 million and $3.6 million for the three and nine months ended September 30, 2015 compared to 2014. The increase in margin is partially offset by increases in operating and depreciation expenses.

Unregulated revenues and margin are primarily associated with PVNGS Unit 3, which currently is not regulated by the NMPRC. Power from PVNGS Unit 3 is sold on the open market. Lower market prices for power in 2015 resulted in lower revenues of $0.2 million and 0.8 million for the three and nine months ended September 30, 2015 than in 2014. Lower nuclear fuel costs decreased cost of energy $0.3 million and $1.0 million for the three and nine months ended September 30, 2015 compared to 2014. Nuclear spent fuel reimbursements from the DOE decreased cost of energy and increased margin $1.9 million for the nine months ended September 30, 2015 compared to 2014. See Note 11. In addition, gas imbalance settlements lowered cost of energy $2.1 million in the nine months ended September 30, 2014, which settlements did not recur in 2015.

PNM’s contract with Gallup, previously its second largest wholesale generation customer, expired on June 29, 2014. For the nine months ended September 30, 2015, a $6.1 million decrease in revenues from the Gallup contract was partially offset by an increase in off-system sales of $1.4 million and lower fuel expense of $1.3 million. PNM’s rate case application filed in August 2015 includes a reallocation of costs among regulatory jurisdictions reflecting the termination of the contract to serve Gallup. See Note 12. Revenues and cost of energy associated with other wholesale contracts decreased $0.5 million for the three months ended September 30, 2015, primarily resulting from lower fuel costs passed through to wholesale customers.

In August 2012, PNM implemented its renewable energy rider, which recovers certain renewable energy procurement costs to meet the RPS. In January 2015, PNM increased the rate charged under the rider to include PNM-owned solar PV facilities completed in 2014. For the three and nine months ended September 30, 2015, this rider increased revenues by $2.7 million and $5.5 million compared to 2014. Revenues under this rider include a return on investment of $1.8 million and $5.4 million for the three and nine months ended September 30, 2015 compared to $1.2 million and $3.7 million for 2014. Cost of energy, reflecting purchase of RECs, increased $0.6 and $1.6 million for the three and nine months ended September 30, 2015 compared to 2014. Revenue and margin from PNM’s energy efficiency rider increased $0.8 million and $1.2 million for the three and nine months ended September 30, 2015 compared to 2014. Revenues from these riders also recover incremental operating, depreciation, and interest expenses applicable to these programs.

Changes in unrealized mark-to-market gains and losses resulted from economic hedges for sales and fuel costs not covered under the FPPAC, primarily associated with PVNGS Unit 3. Unrealized gains of $4.8 million for the three months ended September 30, 2015 compared to unrealized gains of $3.3 million for the three months ended September 30, 2014 increased margin by $1.6 million. Unrealized losses of $1.2 million for the nine months ended September 30, 2015 compared to unrealized gains of $0.1 million for the nine months ended September 30, 2014 decreased margin by $1.3 million.

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Reduced off-system sales and off-system purchases not passed through PNM’s FPPAC decreased revenue $2.1 million and $6.4 million and decreased cost of energy $1.4 million and $6.1 million for the three and nine months ended September 30, 2015 compared to 2014. The reductions were due to less power being available for off-system sales, primarily related to SJGS and lower market prices.

In June 2015, PNM negotiated new gas transportation agreements with El Paso Natural Gas resulting in the refund of previous amounts paid under the FERC tariff and establishing new reduced rates through October 31, 2022. The refund of previously paid gas transportation costs decreased cost of energy and increased margin $4.2 million for the nine months ended September 30, 2015. The newly established rates are anticipated to decrease gas transportation costs approximately $0.8 million on an annual basis.

Changes in revenue, cost of energy, and margin shown as “other” in the table above include a $1.7 million decrease in cost of energy and increase in margin related to the resolution of issues covered by the arbitration with SJCC recorded in the nine months ended September 30, 2014, which did not recur in 2015. See Note 16 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K. As part of the approval of PNM’s FPPAC, beginning July 1, 2013, PNM retains 10% of the revenue from off-system sales that would otherwise be passed through the FPPAC. PNM recorded revenue of $1.2 million in the nine months ended September 30, 2014, which included amounts from July 1, 2013 through September 30, 2014. For the three and nine months ended September 30, 2015, PNM retained revenues of $0.2 million and $0.5 million under this provision.

For the three months ended September 30, 2015, operating expenses increased $3.2 million compared to 2014. Higher maintenance expenses at SJCC, Four Corners, and PVNGS plants of $1.6 million, $1.1 million, and $0.4 million were partially offset by lower maintenance expenses at gas fired plants of $0.3 million. Higher healthcare costs of $2.1 million and higher labor costs of $0.8 million increased operating expenses for the three months ended September 30, 2015 compared to 2014. Lower capitalized administrative and general expenses of $0.4 million increased operating expenses for the three months ended September 30, 2015. In addition, an increase in environmental expenses of $0.6 million and higher energy efficiency expenses, which are recovered through the revenue rider described above, of $0.8 million increased operating expenses for the three months ended September 30, 2015. These expenses were partially offset by the extension of the PVNGS Unit 1 leases on January 15, 2015 at 50% of the rental amounts that were in effect during the original lease term, decreasing operating expenses $4.1 million. The termination of the lease for the 40% interest in the EIP transmission line on April 1, 2015 also decreased operating expenses $0.7 million for the three months ended September 30, 2015 compared to 2014.

For the nine months ended September 30, 2015, operating expenses decreased $3.2 million compared to 2014. The reduced rentals on the PVNGS Unit 1 leases decreased operating expenses $11.7 million for the nine months ended September 30, 2015 compared to 2014. Higher maintenance expenses at SJCC, Four Corners, PVNGS, and natural gas-fired plants of $1.6 million, $2.5 million, $2.1 million, and $0.3 million increased operating expenses. Lower pension expenses of $1.0 million and higher capitalized administrative and general expenses of $1.3 million, due to increased capital spending, reduced operating expenses for the nine months ended September 30, 2015 compared to 2014. In the nine months ended September 30, 2014, PNM undertook process improvement initiatives designed to decrease future operating expenses. In connection with those initiatives, PNM incurred costs, primarily related to severances, of $1.8 million that decreased operating expenses for the nine months ended June 30, 2015 compared to 2014. In addition, the termination of the EIP lease decreased operating expenses $1.4 million in the nine months ended September 30, 2015. Higher healthcare costs of $2.5 million and higher labor costs of $0.7 million increased operating expenses for the nine months ended September 30, 2015. The increase in environmental expenses of $0.6 million and higher energy efficiency expenses of $1.7 million increased expenses for the nine months ended September 30, 2015. During the nine months ended September 30, 2015, PNM concluded that certain costs that were being deferred as regulatory assets were no longer probable of recovery through the ratemaking process and recorded regulatory disallowances of $1.7 million

Depreciation and amortization expense increased $1.5 million and $4.8 million for the three and nine months ended September 30, 2015 compared to 2014 due to additions to utility plant in service, including the addition of 23 MW of PNM-owned solar PV facilities in late 2014 and the purchase of Rio Bravo in July 2014.

Other income (deductions) increased $2.7 million and $8.4 million for the three and nine months ended September 30, 2015 compared to 2014. Pre-tax gains on available-for-sale securities, reflecting performance of the NDT and the trust for coal mine reclamation, increased other income (deductions) $1.6 million and $3.9 million in the three and nine months ended September 30, 2015 compared to 2014. Higher fees and taxes on the NDT decreased other income (deductions) by $0.9 million and $2.1 million in the three and nine months ended September 30, 2015. Income of $1.4 million and $3.4 million from refined coal (a third-party pre-treatment process) at SJGS increased other income (deductions) for the three and nine months ended September

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30, 2015 compared to 2014. Higher equity AFUDC of $2.2 million and $3.5 million due to increased levels of construction also increased other income (deductions) in 2015. PNM recognized a gain of $1.1 million in the nine months ended September 30, 2015 from the sale to Gallup of substations and associated transmission facilities owned by PNM that had been used solely to provide service to Gallup prior to the termination of PNM’s electric service agreement with Gallup discussed above. Changes in the amounts of losses on retirements of PVNGS Unit 3 assets decreased other income (deductions) $0.1 million for the three months ended September 30, 2015 compared to 2014, but increased other income (deductions) $0.5 million for the nine months ended September 30, 2015. Interest income on PVNGS lessor notes decreased $0.6 million and $1.8 million during the three and nine months ended September 30, 2015 compared to 2014 due to lower outstanding principal balances under the notes.

Interest charges decreased $0.3 million and $0.4 million for the three and nine months ended September 30, 2015 compared to 2014 due to higher debt AFUDC, partially offset by higher cost of borrowings for the $250.0 million Senior Unsecured Notes issued on August 11, 2015 Note 9 compared to the debt paid off with the proceeds of that offering.

As discussed in Note 13, the Company settled an IRS examination in June 2014. As a result of the settlement, PNM recorded an additional income tax expense of $1.1 million in the three months ended June 30, 2014. This amount partially offsets an income tax benefit of $1.3 million reflected in the Corporate and Other segment.

TNMP

The following table summarizes the operating results for TNMP:



	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Electric operating revenues	$	84.0		$	79.0		$	5.0		$	232.4		$	215.6		$	16.8
Cost of energy	18.5			17.4			1.1			54.6			50.2			4.4
Margin	65.4			61.6			3.8			177.7			165.4			12.3
Operating expenses	22.8			22.3			0.5			65.3			63.7			1.6
Depreciation and amortization	15.0			13.4			1.6			42.1			37.3			4.8
Operating income	27.7			25.9			1.8			70.3			64.4			5.9
Other income (deductions)	0.7			0.8			(0.1		)	2.8			1.5			1.3
Net interest charges	(6.9		)	(6.9		)	—			(20.6		)	(20.1		)	(0.5		)
Segment earnings before income taxes	21.5			19.8			1.7			52.4			45.8			6.6
Income (taxes)	(7.8		)	(7.4		)	(0.4		)	(19.2		)	(17.1		)	(2.1		)
Segment earnings	$	13.7		$	12.4		$	1.3		$	33.2		$	28.7		$	4.5

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The following table summarizes the significant changes to total electric operating revenues, cost of energy, and margin:



	2014/2015 Change
	Three Months Ended September 30,								Nine Months Ended September 30,
	Electric								Electric
	Operating			Cost of					Operating			Cost of
	Revenues			Energy		Margin			Revenues			Energy		Margin
	(In millions)
Rate increases	$	2.2		$	—	$	2.2		$	6.4		$	—	$	6.4
Customer usage	0.1			—		0.1			1.7			—		1.7
Customer growth	0.5			—		0.5			1.2			—		1.2
Weather	0.8			—		0.8			0.6			—		0.6
Recovery of third-party transmission costs	1.1			1.1		—			4.4			4.4		—
AMS surcharge	0.8			—		0.8			3.6			—		3.6
Energy efficiency incentive bonus	(0.8		)	—		(0.8		)	(0.8		)	—		(0.8		)
Other	0.3			—		0.3			(0.3		)	—		(0.3		)
Net change	$	5.0		$	1.1	$	3.8		$	16.8		$	4.4	$	12.3

The following table shows total electric operating revenues by retail tariff consumer class, including intersegment revenues, and average number of consumers:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2015		2014		Change		2015		2014		Change
	(In millions, except consumers)
Residential	$	39.4	$	36.6	$	2.8	$	94.1	$	89.5	$	4.6
Commercial	26.0		25.1		0.9		76.1		73.5		2.6
Industrial	4.1		3.9		0.2		12.1		11.1		1.0
Other	14.5		13.4		1.1		50.1		41.5		8.6
	$	84.0	$	79.0	$	5.0	$	232.4	$	215.6	$	16.8
Average consumers (thousands) ⁽¹⁾	242.2		238.9		3.3		241.2		237.7		3.5


⁽¹⁾	TNMP provides transmission and distribution services to REPs that provide electric service to consumers in TNMP’s service territories. The number of consumers above represents the customers of these REPs. Under TECA, consumers in Texas have the ability to choose any REP to provide energy.

The following table shows GWh sales by retail tariff consumer class:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2015	2014 ⁽¹⁾	Change		2015	2014 ⁽¹⁾	Change
	(Gigawatt hours)
Residential	993.2	938.8	54.4		2,338.3	2,227.9	110.4
Commercial	767.5	737.2	30.3		2,020.3	1,944.7	75.6
Industrial	694.2	709.6	(15.4	)	2,083.4	2,014.2	69.2
Other	26.5	26.4	0.1		76.1	75.9	0.2
	2,481.4	2,412.0	69.4		6,518.1	6,262.7	255.4


⁽¹⁾	The 2014 GWh amounts reflect a reclassification of 5.6 GWh and 18.1 GWh from industrial to commercial for the three and nine months ended September 30, 2014 to be consistent with the current year presentation.

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For the three and nine months ended September 30, 2015, revenues and margin increased by $2.2 million and $6.4 million compared to 2014 due to transmission cost of service rate increases in March 2014, September 2014, March 2015, and September 2015. See Note 12. TNMP’s weather normalized retail KWh sales increased 1.5% and 2.7% for the three and nine months ended September 30, 2015 compared to 2014. Higher weather normalized usage per customer increased revenues and margin by $0.1 million and $1.7 million for the three and nine months ended September 30, 2015 compared to 2014. Warmer weather in the summer months of 2015 compared to 2014, partially offset by milder weather in the winter months, increased revenues and margins by $0.8 million and $0.6 million for the three and nine months ended September 30, 2015 compared to 2014. For the three and nine months ended September 30, 2015 compared to 2014, cooling degree days were 8.2% higher and 5.1% higher and heating degree days were flat and 3.4% lower. TNMP also experienced positive year to date average customer growth of 1.5%, increasing revenues and margin by $0.5 million and $1.2 million for the three and nine months ended September 30, 2015 compared to 2014.

Changes in costs charged by third party transmission providers are deferred and recovered through a transmission cost recovery factor resulting in no impact on margin. Higher transmission costs resulting from rate increases from other transmission service providers within ERCOT increased cost of energy $1.1 million and $4.4 million for the three and nine months ended September 30, 2015 compared to 2014. These increases in cost of energy resulted in TNMP rate increases for the recovery of third party transmission costs increasing revenue $1.1 million and $4.4 million for the three and nine months ended September 30, 2015 compared to 2014.

TNMP earned energy efficiency incentive bonuses for having achieved demand savings for the 2013 and 2014 program years that exceeded its goal. The $1.5 million incentive bonus for the 2013 program year was approved by the PUCT on September 11, 2014 and the $0.7 million incentive bonus for the 2014 program year was approved by the PUCT on September 11, 2015. The lower incentive bonus decreased revenues and margin by $0.8 million for the three and nine months ended September 30, 2015. See Note 12.

The AMS surcharge increased revenues and margin by $0.8 million and $3.6 million for the three and nine months ended September 30, 2015 compared to 2014. Other in the table above, which includes recovery of the CTC, rate case expenses, and energy efficiency programs, was slightly higher for the three months ended September 30, 2015 and slightly lower for the nine months ended September 30, 2015 compared to 2014. Changes in these revenues were offset by changes in operating and depreciation and amortization expenses.

Operating expenses increased $0.5 million and $1.6 million for the three and nine months ended September 30, 2015 compared to 2014. Higher employee healthcare costs of $0.8 million and $1.5 million, higher property taxes, resulting from higher plant in service balances, of $0.4 million and $1.1 million, and higher street rental taxes of $0.2 million and $0.3 million for the three and nine months ended September 30, 2015 increased operating expenses compared to 2014. These increases were partially offset by higher capitalization of administrative and general expenses related to higher levels of construction expenditures, which decreased operating expenses by $1.3 million for the three and nine months ended September 30, 2015 compared to 2014. In addition, property and casualty claims were $0.3 million higher for the three months ended September 30, 2015 but $0.3 million lower for the nine months ended September 30, 2015.

Depreciation and amortization increased $1.6 million and $4.8 million for the three and nine months ended September 30, 2015 compared to 2014. Depreciation expense associated with the AMS deployment, which is recovered through the AMS surcharge, increased $0.7 million and $2.3 million for the three and nine months ended September 30, 2015 compared to 2014 due to increased AMS deployment. Amortization expense associated with the CTC, which is recovered through the CTC surcharge, increased $0.3 million and $0.7 million for the three and nine months ended September 30, 2015 compared to 2014. In addition, an increase in utility plant in service increased depreciation by $0.6 million and $1.8 million for the three and nine months ended September 30, 2015 compared to 2014.

Other income (deductions) decreased $0.1 million and increased $1.3 million for the three and nine months ended September 30, 2015, primarily due to changes in contributions in aid of construction.

Net interest charges were flat and increased $0.5 million for the three and nine months ended September 30, 2015 compared to 2014. Interest charges related to the June 27, 2014 issuance of $80.0 million of long-term debt under the TNMP 2013 Bond Purchase Agreement increased interest expense $1.6 million for the nine months ended September 30, 2015. This was partially offset by lower interest charges of $1.0 million for the nine months ended September 30, 2015, due to the June 30, 2014 maturity of $50.0 million of debt under the TNMP 2011 Term Loan Agreement. See Note 9.

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Corporate and Other

The table below summarizes the operating results for Corporate and Other:



	Three Months Ended September 30,									Nine Months Ended September 30,
	2015			2014			Change			2015			2014			Change
	(In millions)
Total revenues	$	—		$	—		$	—		$	—		$	—		$	—
Cost of energy	—			—			—			—			—			—
Margin	—			—			—			—			—			—
Operating expenses	(3.6		)	(3.7		)	0.1			(11.1		)	(10.2		)	(0.9		)
Depreciation and amortization	3.4			3.3			0.1			10.5			9.5			1.0
Operating income	0.1			0.3			(0.2		)	0.6			0.7			(0.1		)
Other income (deductions)	(0.5		)	(0.6		)	0.1			(3.0		)	(1.6		)	(1.4		)
Net interest charges	(0.8		)	(3.2		)	2.4			(6.6		)	(9.6		)	3.0
Segment earnings (loss) before income taxes	(1.2		)	(3.4		)	2.2			(8.9		)	(10.4		)	1.5
Income (taxes) benefit	(0.7		)	1.5			(2.2		)	2.1			6.0			(3.9		)
Segment earnings (loss)	$	(1.9	)	$	(1.9	)	$	—		$	(6.8	)	$	(4.4	)	$	(2.4	)

Corporate and Other operating expenses shown above are net of amounts allocated to PNM and TNMP under shared services agreements. The amounts allocated include certain expenses shown as depreciation and amortization and other income (deductions) in the table above.

Depreciation expense increased in the three and nine months ended September 30, 2015 from 2014 due to additions of computer software. Substantially all depreciation and amortization expense is offset in operating expenses as a result of allocation of these costs to other business segments.

Other income (deductions) includes losses of $1.1 million recorded in the three months ended March 31, 2015 for items included in other investments related to a former PNMR subsidiary, which ceased operations in 2008. The decrease in net interest charges is primarily related to the maturity of PNMR’s $118.8 million of 9.25% Senior Unsecured Notes, Series A on May 15, 2015, partially offset by interest on PNMR’s new $150 million PNMR 2015 Term Loan Agreement entered into on March 9, 2015. See Note 9.

Income taxes (benefit) is impacted by the impairments of wind energy production tax credits of $1.0 million and $1.1 million (net of federal income tax benefit) and New Mexico state net operating losses of $0.1 million and $0.4 million (net of federal income tax benefit) in the three and nine months ended September 30, 2015. Additionally, a tax benefit of $0.2 million and a tax expense of $0.2 million were recorded in the three months ending March 31, 2015 and 2014 resulting from refinements of the impacts of a phased-in reduction in New Mexico corporate income tax rates. In June 2014, the Company settled the IRS examination that resulted in an income tax benefit of $1.3 million in the three months ended June 30, 2014. This amount was partially offset by an additional income tax expense reflected in the PNM segment.

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LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the nine months ended September 30, 2015 compared to September 30, 2014 are summarized as follows:



	Nine Months Ended September 30,
	2015			2014			Change
	(In millions)
Net cash flows from:
Operating activities	$	335.6		$	326.2		$	9.4
Investing activities	(387.2		)	(311.7		)	(75.5		)
Financing activities	50.3			11.3			39.0
Net change in cash and cash equivalents	$	(1.3	)	$	25.9		$	(27.2	)

Changes in PNMR’s cash flows from operating activities result from net earnings, adjusted for items impacting earnings that do not provide or use cash. See Results of Operations above. Certain changes in assets and liabilities resulting from normal operations also impact operating cash flows. Cash flows from operating activities also increased $44.4 million in the nine months September 30, 2015 compared to 2014 related to the collection of amounts deferred in PNM’s FPPAC resulting from the cap on amounts passed through to ratepayers prior to June 30, 2014. In addition, contributions to PNMR’s pension and postretirement benefit plans were $29.7 million higher in the nine months ended September 30, 2015 than in 2014.

The changes in PNMR’s cash flows from investing activities relate primarily to an increase of $118.2 million in utility plant additions in the nine months ended September 30, 2015 compared to 2014. Utility plant additions at PNM were $101.6 million higher in the nine months ended September 30, 2015 compared to 2014, including increases in generation additions of $90.0 million and transmission and distribution additions of $15.3 million, offset by lower nuclear fuel purchases of $3.7 million. TNMP utility plant additions increased $1.6 million in the nine months ended September 30, 2015 compared to 2014, including increases in transmission and distribution additions of $5.3 million and a decrease in AMS additions of $3.8 million. Corporate plant additions increased $15.1 million in the nine month ended September 30, 2015 compared to 2014, including increases for computer hardware and software additions of $11.3 million and PNMR Development utility plant additions of $3.8 million. Investing activities in 2014 also includes $36.2 million for the acquisition of Rio Bravo as discussed in Note 5.

The changes in PNMR’s cash flows from financing activities include a $46.2 million increase in net short-term borrowing repayments in the nine months ended September 30, 2015 compared to 2014. In 2015, financing activities include $150.0 million of long-term borrowings under the PNMR 2015 Term Loan Agreement and $25.0 million of additional long-term borrowings under the PNM Multi-draw Term Loan. PNMR used portions of the proceeds to repay $118.8 million of 9.25% senior unsecured notes that matured on May 15, 2015 and for general corporate purposes. In 2015, PNM also issued $250.0 million aggregate principal amount of its 3.850% Senior Unsecured Notes due 2025. PNM used the proceeds to repay the $175.0 million PNM 2014 Term Loan agreement and outstanding borrowings under the PNM Revolving Credit Facility, the PNM New Mexico Credit Facility, and PNM’s intercompany loan from PNMR. In 2015, PNM also successfully remarketed $39.3 million of senior unsecured notes, pollution control revenue bonds. In 2014, long-term borrowings of $175.0 million under the PNM 2014 Term Loan Agreement were used to repay amounts under the existing $75.0 million PNM Term Loan Agreement and reduce short-term debt. In 2014, TNMP long-term borrowings of $80.0 million were used to repay amounts under the existing $50.0 million TNMP 2011 Term Loan Agreement and other short-term borrowings.

Financing Activities

See Note 6 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K and Note 9 for additional information concerning the Company’s financing activities. PNM must obtain NMPRC approval for any financing transaction having a maturity of more than 18 months. In addition, PNM files its annual short-term financing plan with the NMPRC. The Company’s ability to access the credit and capital markets at a reasonable cost is largely dependent upon its:


•	Ability to earn a fair return on equity


•	Results of operations

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•	Ability to obtain required regulatory approvals


•	Conditions in the financial markets


•	Credit ratings

On March 9, 2015, PNMR entered into the $150.0 million PNMR 2015 Term Loan Agreement between PNMR, the lenders identified therein, and Wells Fargo Bank, National Association, as Lender and Administrative Agent. The PNMR 2015 Term Loan Agreement bears interest at a variable rate and must be repaid on or before March 9, 2018. The PNMR 2015 Term Loan Agreement includes customary covenants and conditions. PNMR utilized a portion of the proceeds from the PNMR 2015 Term Loan Agreement and borrowings under the PNMR Revolving Credit Facility to retire the $118.8 million of 9.25% Senior Unsecured Notes, Series A when they matured on May 15, 2015. In September 2015, PNMR entered into a hedging agreement whereby it effectively established a fixed interest rate of 2.027% for borrowings under the PNMR 2015 Term Loan Agreement for the period from January 11, 2016 through March 9, 2018.

PNMR, PNM, and TNMP are subject to debt-to-capital ratio requirements of less than or equal to 65%. These ratios for PNMR and PNM include the present value of payments under the PVNGS leases as debt. At September 30, 2015, interest rates on outstanding borrowings were 1.05% for the PNMR Term Loan Agreement, 1.21% for the PNMR 2015 Term Loan Agreement, and 0.78% for the PNM Multi-draw Term Loan.

Capital Requirements

Total capital requirements consist of construction expenditures and cash dividend requirements for PNMR common stock and PNM preferred stock. Key activities in PNMR’s current construction program include:


•	Upgrading generation resources, including expenditures for compliance with environmental requirements and for renewable energy resources


•	Expanding the electric transmission and distribution systems


•	Purchasing nuclear fuel

Projected capital requirements, including amounts expended through September 30, 2015 , are:



	2015		2016-2019		Total
	(In millions)
Construction expenditures	$	576.5	$	1,706.1	$	2,282.6
Dividends on PNMR common stock	63.7		254.9		318.6
Dividends on PNM preferred stock	0.5		2.1		2.6
Total capital requirements	$	640.7	$	1,963.1	$	2,603.8

The construction expenditure estimates are under continuing review and subject to ongoing adjustment, as well as to Board review and approval. The construction expenditures above include estimated amounts of $60.0 million related to environmental upgrades at SJGS to address regional haze, including amounts for the 65 MW anticipated to be owned by PNMR Development, and $179.8 million related to the identified sources of replacement capacity under the revised plan for compliance described in Note 11. The above construction expenditures also include additional renewable resources anticipated to be required to meet the RPS, peaking resources to meet needs outlined in PNM’s current IRP, environmental upgrades at Four Corners of $91.4 million, the purchase of the leased portion of the EIP on April 1, 2015, and the purchase of the assets underlying three of the PVNGS Unit 2 leases at the expiration of those leases in 2016. Expenditures for the SJGS and Four Corners environmental upgrades are estimated to be $63.8 million in 2015. See Note 11 and Commitments and Contractual Obligations below. The ability of PNMR to pay dividends on its common stock is dependent upon the ability of PNM and TNMP to be able to pay dividends to PNMR. Note 5 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K describes regulatory and contractual restrictions on the payment of dividends by PNM and TNMP.

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During the nine months ended September 30, 2015 , PNMR met its capital requirements and construction expenditures through cash generated from operations, as well as its liquidity arrangements, additional term loan borrowings, and the issuance of the 3.850% Senior Unsecured Notes by PNM.

In addition to the capital requirements for construction expenditures and dividends, the Company has long-term debt that must be paid or refinanced at maturity. PNMR’s $118.8 million of 9.25% Senior Unsecured Notes, Series A matured and were repaid on May 15, 2015; $39.3 million of PNM’s PCRBs were subject to mandatory tender for remarketing on June 1, 2015 (the bonds were remarketed on that date and are next subject to mandatory tender for remarketing on June 1, 2020); the $175.0 million PNM 2014 Term Loan Agreement was repaid on August 12, 2015; and the $125.0 million PNM Multi-draw Term Loan matures on June 21, 2016. Note 6 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K contains information about the maturities of long-term debt. Also, the one-year $100.0 million PNMR Term Loan Agreement matures on December 21, 2015. PNMR and PNM anticipate that funds to repay the long-term debt maturities and term loans will come from entering into new arrangements similar to the existing agreements, cash and cash equivalents, borrowing under their revolving credit facilities, issuance of new long-term debt, or a combination of these sources. The Company has from time to time refinanced or repurchased portions of its outstanding debt before scheduled maturity. Depending on market conditions, the Company may refinance other debt issuances, make additional debt repurchases, or enter into other liquidity arrangements in the future.

Liquidity

PNMR’s liquidity arrangements include the PNMR Revolving Credit Facility and the PNM Revolving Credit Facility that both have been extended to expire in October 2020 and the TNMP Revolving Credit Facility that expires in September 2018. The PNMR Revolving Credit Facility has a financing capacity of $300.0 million, the PNM Revolving Credit Facility has a financing capacity of $400.0 million, and the TNMP Revolving Credit Facility has a financing capacity of $75.0 million. PNM also has the $50.0 million PNM New Mexico Credit Facility, which expires on January 8, 2018. The Company believes the terms and conditions of its facilities are consistent with those of other investment grade revolving credit facilities in the utility industry.

The revolving credit facilities and the PNM New Mexico Credit Facility provide short-term borrowing capacity. The revolving credit facilities also allow letters of credit to be issued. Letters of credit reduce the available capacity under the facilities. The Company utilizes these credit facilities and cash flows from operations to provide funds for both construction and operational expenditures. The Company’s business is seasonal with more revenues and cash flows from operations being generated in the summer months. In general, the Company relies on the credit facilities to be the initial funding source for construction expenditures. Accordingly, borrowings under the facilities may increase over time. Depending on market and other conditions, the Company will periodically sell long-term debt and use the proceeds to reduce the borrowings under the credit facilities. Borrowings under the PNMR Revolving Credit Facility ranged from zero to $25.6 million during the three and nine months ended September 30, 2015 . Borrowings under the PNM Revolving Credit Facility ranged from zero to $48.4 million during the three and nine months ended September 30, 2015 . Borrowings under the PNM New Mexico Credit Facility ranged from zero to $20.0 million during the three and nine months ended September 30, 2015 . Borrowings under the TNMP Revolving Credit Facility ranged from zero to $37.0 million during the three and nine months ended September 30, 2015 . At September 30, 2015 , the average interest rate was 1.69% under the PNMR Revolving Credit Facility. At September 30, 2015 , TNMP had $48.5 million in borrowings from PNMR under its intercompany loan agreements.

The Company currently believes that its capital requirements can be met through internal cash generation, existing or new credit arrangements, and access to public and private capital markets. To cover the difference in the amounts and timing of internal cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if difficult market conditions experienced during the recent recession return, the Company may not be able to access the capital markets or renew credit facilities when they expire. Should that occur, the Company would seek to improve cash flows by reducing capital expenditures and exploring other available alternatives. Also, PNM could consider seeking authorization for the issuance of first mortgage bonds to improve access to the capital markets.

In addition to its internal cash generation, the Company anticipates that it will be necessary to obtain additional long-term financing to fund its capital requirements during the 2015-2019 period. This could include debt refinancing, new debt issuances, and/or new equity.

Information concerning the credit ratings for PNMR, PNM, and TNMP was set forth under the heading Liquidity in the MD&A contained in the 2014 Annual Reports on Form 10-K. As discussed above, PNMR retired the 9.25% Senior Unsecured Notes, Series A when they matured on May 15, 2015, which results in PNMR having no senior unsecured notes outstanding. Following this repayment, Moody’s and S&P withdrew their ratings of PNMR senior unsecured debt. On June 22, 2015, Moody’s assigned an issuer rating of Baa3 to PNMR, upgraded the issuer rating of TNMP to A3 from Baa1, upgraded the senior secured

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debt rating of TNMP to A1 from A2, and changed the outlook for PNMR, PNM, and TNMP to stable from positive. As of October 23, 2015 , ratings on the Company’s securities were as follows:



	PNMR	PNM	TNMP
S&P
Corporate rating	BBB	BBB	BBB
Senior secured debt	*	*	A-
Senior unsecured debt	*	BBB	*
Preferred stock	*	BB+	*
Moody’s
Issuer rating	Baa3	Baa2	A3
Senior secured debt	*	*	A1
Senior unsecured debt	*	Baa2	*

* Not applicable

S&P has PNMR, PNM, and TNMP on positive outlook and Moody’s has all entities on a stable outlook. However, negative regulatory outcomes from the NMPRC in the SJGS BART filing, discussed in Note 11, could affect both the outlook and credit ratings. Investors are cautioned that a security rating is not a recommendation to buy, sell, or hold securities, that it is subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

A summary of liquidity arrangements as of October 23, 2015 is as follows:



	PNMR Separate		PNM Separate		TNMP Separate		PNMR Consolidated
	(In millions)
Financing capacity:
Revolving credit facility	$	300.0	$	400.0	$	75.0	$	775.0
PNM New Mexico Credit Facility	—		50.0		—		50.0
Total financing capacity	$	300.0	$	450.0	$	75.0	$	825.0


Amounts outstanding as of October 23, 2015:
Revolving credit facility	$	—	$	—	$	20.0	$	20.0
PNM New Mexico Credit Facility	—		—		—		—
Letters of credit	6.2		3.2		0.1		9.5

Total short-term debt and letters of credit	6.2		3.2		20.1		29.5

Remaining availability as of October 23, 2015	$	293.8	$	446.8	$	54.9	$	795.5
Invested cash as of October 23, 2015	$	11.0	$	34.1	$	—	$	45.1

The above table excludes intercompany debt. As of October 23, 2015 , TNMP had $36.8 million in borrowings from PNMR under an intercompany loan agreement. The remaining availability under the revolving credit facilities at any point in time varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures.

PNMR can offer new shares of common stock through the PNM Resources Direct Plan under a SEC shelf registration statement that expires in August 2018. PNM has a shelf registration statement, which expires in May 2017, with capacity for up to $250.0 million of senior unsecured notes.

Off-Balance Sheet Arrangements

PNMR’s off-balance sheet arrangements include PNM’s operating lease obligations for PVNGS Units 1 and 2 and, until April 1, 2015, the EIP transmission line. These arrangements help ensure PNM the availability of lower-cost generation needed

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to serve customers. See MD&A – Off-Balance Sheet Arrangements and Notes 7 and 9 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K as well as Note 5.

Commitments and Contractual Obligations

PNMR, PNM, and TNMP have contractual obligations for long-term debt, operating leases, construction expenditures, purchase obligations, and certain other long-term obligations. See MD&A – Commitments and Contractual Obligations in the 2014 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2014 Annual Reports on Form 10-K, PNMR, PNM, and TNMP have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. In the unlikely event that the contingent requirements were to be triggered, PNMR, PNM, or TNMP could be required to provide security, immediately pay outstanding obligations, or be prevented from drawing on unused capacity under certain credit agreements. The contingent provisions also include contractual increases in the interest rate charged on certain of the Company’s short-term debt obligations in the event of a downgrade in credit ratings. The Company believes its financing arrangements are sufficient to meet the requirements of the contingent provisions. No conditions have occurred that would result in any of the above contingent provisions being implemented.

Capital Structure

The capitalization tables below include the current maturities of long-term debt, but do not include short-term debt and do not include operating lease obligations as debt.



	September 30, 2015		December 31, 2014
PNMR
PNMR common equity	45.4	%	46.4	%
Preferred stock of subsidiary	0.3	%	0.3	%
Long-term debt	54.3	%	53.3	%
Total capitalization	100.0	%	100.0	%

PNM
PNM common equity	44.6	%	45.7	%
Preferred stock	0.4	%	0.4	%
Long-term debt	55.0	%	53.9	%
Total capitalization	100.0	%	100.0	%

TNMP
Common equity	59.6	%	58.9	%
Long-term debt	40.4	%	41.1	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2014, GHG associated with PNM’s interests in its generating plants included approximately 6.7 million metric tons of CO ₂ , which comprises the vast majority of PNM’s GHG. By comparison, the total GHG in the United States in 2013, the latest year for which EPA has published this data, were approximately 6.7 billion metric tons, of which approximately 5.5 billion metric tons were CO ₂ .

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PNM has several programs underway to reduce or offset GHG from its resource portfolio, thereby reducing its exposure to climate change regulation. See Note 12. In 2011, PNM completed construction of 22 MW of utility-scale solar generation located at five sites on PNM’s system throughout New Mexico. In 2013, PNM expanded its renewable energy portfolio by constructing 21.5 MW of utility-scale solar generation. In 2014, PNM added an additional 23 MW of utility-scale solar generation. PNM’s 2015 renewable energy procurement includes the construction of an additional 40 MW of PNM-owned solar PV facilities by December 31, 2015. Since 2003, PNM has purchased the entire output of New Mexico Wind, which has an aggregate capacity of 204 MW, and began purchasing the full output of Red Mesa Wind, which has an aggregate capacity of 102 MW, in January 2015. PNM has signed a 20-year PPA for the output of Lightning Dock Geothermal, which began providing power to PNM in January 2014. The current capacity of the geothermal facility is 3 MW and future expansion may result in up to 10 MW of generation capacity. Additionally, PNM has a customer distributed solar generation program that represented 43 MW at September 30, 2015 and is expected to grow to over 45 MW by the end of 2015. PNM’s distributed solar programs will reduce PNM’s annual production from fossil-fueled electricity generation by about 120 GWh. PNM offers its customers a comprehensive portfolio of energy efficiency and load management programs, with a 2014 budget of $22.5 million and anticipated program costs of $25.8 million for the program year beginning in June 2015. PNM estimates these programs saved approximately 75 GWh of electricity in 2014. Over the next 20 years, PNM projects energy efficiency and load management programs will provide the equivalent of approximately 13,000 GWh of electricity, which will avoid at least 6.5 million metric tons of CO ₂ based upon projected emissions from PNM’s system-wide resources. These estimates are subject to change because of the uncertainty of many of the underlying variables, including changes in demand for electricity, and complex relationships between those variables.

Management periodically updates the Board on implementation of the corporate environmental policy and the Company’s environmental management systems, promotion of energy efficiency, and use of renewable resources. The Board is also advised of the Company’s practices and procedures to assess the sustainability impacts of operations on the environment. The Board considers associated issues around climate change, the Company’s GHG exposures, and the financial consequences that might result from potential federal and/or state regulation of GHG.

As of December 31, 2014, approximately 71.2% of PNM’s generating capacity, including resources owned, leased, and under PPAs, all of which is located within the United States, consisted of coal or gas-fired generation that produces GHG. Based on current forecasts, the Company does not expect its output of GHG from existing sources to increase significantly in the near-term. Many factors affect the amount of GHG emitted. For example, if new natural gas-fired generation resources are added to meet increased load as anticipated in PNM’s current IRP, GHG would be incrementally increased. In addition, plant performance could impact the amount of GHG emitted. If PVNGS experienced prolonged outages, PNM might be required to utilize other power supply resources such as gas-fired generation, which could increase GHG. As described in Note 11, on February 15, 2013, PNM, NMED, and EPA agreed to pursue a strategy to address the regional haze requirements of the CAA at the coal-fired SJGS, which would include the shutdown of SJGS Units 2 and 3. The shutdown of Units 2 and 3 would result in a reduction of GHG of approximately 50% at SJGS. Although replacement power strategies include some gas-fired generation, the reduction in GHG from the retirement of the coal-fired generation would be far greater than the increase in GHG from replacement generation. In September 2013, the EIB approved a RSIP submitted by NMED that encompassed the February 15, 2013 agreement. EPA published final rules approving the RSIP and withdrawing the previously issued FIP in the Federal Register on October 9, 2014 and the rules became effective on November 10, 2014.

Because of PNM’s dependence on fossil-fueled generation, legislation or regulation that imposes a limit or cost on GHG could impact the cost at which electricity is produced. While PNM expects to recover any such costs through rates, the timing and outcome of proceedings for cost recovery are uncertain. In addition, to the extent that any additional costs are recovered through rates, customers may reduce their usage, relocate facilities to other areas with lower energy costs, or take other actions that ultimately will adversely impact PNM.

Given the geographic location of its facilities and customers, PNM generally has not been exposed to the extreme weather events and other physical impacts commonly attributed to climate change, with the exception of periodic drought conditions. Drought conditions in northwestern New Mexico could impact the availability of water for cooling coal-fired generating plants. Water shortage sharing agreements have been in place since 2004, although no shortage has been declared due to sufficient precipitation in the San Juan River basin. PNM also has a supplemental water contract in place with the Jicarilla Apache Nation to help address any water shortages from primary sources. The contract expires on December 31, 2016. PNM’s service areas also experience periodic high winds, forest fires, and severe thunderstorms. TNMP has operations in the Gulf Coast area of Texas, which experiences periodic hurricanes and drought conditions. In addition to potentially causing physical damage to TNMP-owned facilities, which disrupt the ability to transmit and/or distribute energy, hurricanes can temporarily reduce customers’ usage and demand for energy. Climate changes are generally not expected to have material consequences to the Company in the near-term.

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EPA Regulation

In April 2007, the United States Supreme Court held that EPA has the authority to regulate GHG under the CAA. This decision heightened the importance of this issue for the energy industry. In December 2009, EPA released its endangerment finding stating that the atmospheric concentrations of six key greenhouse gases (CO ₂ , methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. In May 2010, EPA released the final PSD and Title V Greenhouse Gas Tailoring Rule (the “Tailoring Rule”) to address GHG from stationary sources under the CAA permitting programs. The purpose of the rule was to “tailor” the applicability of two programs, PSD and Title V operating permit programs, to avoid impacting millions of small GHG emitters. The rule focused on the largest sources of GHG, including fossil-fueled electric generating units. This program covered the construction of new emission units that emit GHG of at least 100,000 tons per year in CO ₂ equivalents (even if PSD is not triggered for other pollutants). In addition, modifications at existing major-emitting facilities that increase GHG by at least 75,000 tons per year in CO ₂ equivalents would be subject to PSD permitting requirements, even if they did not significantly increase emissions of any other pollutant. As a result, PNM’s fossil-fueled generating plants were more likely to trigger PSD permitting requirements because of the magnitude of GHG. However as discussed below, a court case in 2014 now limits the extent of the Tailoring Rule.

On June 26, 2012, the D.C. Circuit rejected challenges to EPA’s 2009 GHG endangerment finding, GHG standards for light-duty vehicles, PSD Interpretive Memorandum (EPA’s so-called GHG “Timing Rule”), and the Tailoring Rule. The Court found that EPA’s endangerment finding and its light-duty vehicle rule “are neither arbitrary nor capricious,” that “EPA’s interpretation of the governing CAA provisions is unambiguously correct,” and that “no petitioner has standing to challenge the Timing and Tailoring Rules.” On October 15, 2013, the United States Supreme Court granted a petition for a Writ of Certiorari regarding the permitting of stationary sources that emit GHG. The Supreme Court limited the question that it would review to: “Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the Clean Air Act for stationary sources that emit greenhouse gases.” Specifically, the case dealt with whether EPA’s determination that regulation of GHG from motor vehicles required EPA to regulate stationary sources under the PSD and Title V permitting programs. The petitioners argued that EPA’s determination that it was required to regulate GHG under the PSD and Title V Programs was unlawful as it violates Congressional intent.

On June 23, 2014, the United States Supreme Court issued its opinion on the above case. The Supreme Court largely reversed the D.C. Circuit. First, the Supreme Court found the CAA does not compel or permit EPA to adopt an interpretation of the act that requires a source to obtain a PSD or Title V permit on the sole basis of its potential GHG. Second, EPA had argued that even if it was not required to regulate GHGs under the PSD and Title V programs, the Tailoring Rule was nonetheless justified on the grounds that it was a reasonable interpretation of the CAA. The Supreme Court rejected this argument. Third, the Supreme Court found EPA lacked authority to "tailor" the CAA's unambiguous numerical thresholds of 100 or 250 tons per year. Fourth, the Supreme Court found that it would be reasonable for EPA to interpret the CAA to limit the PSD program for GHGs to "anyway" sources – those sources that have to comply with the PSD program for other non-GHG pollutants. The Supreme Court said that EPA needed to establish a de minimis level below which BACT would not be required for "anyway" sources.

On March 27, 2012, EPA issued its proposed carbon pollution standards, under Section 111(b) of the CAA, for GHG from new fossil-fueled EGUs larger than 25 MW. The proposed limit was based on the performance of natural gas combined cycle technology. Therefore, coal-fired power plants would only be able to comply with the standard by using carbon capture and sequestration technology. The proposed rule included an exemption for new simple cycle EGUs. EPA accepted comment on the proposed rule through June 25, 2012, during which EPA received over 2.5 million comments. As a result of the comments, EPA reproposed the EGU NSPS as discussed below.

On June 25, 2013, President Obama announced his Climate Action Plan which outlines how his administration plans to cut GHG in the United States, prepare the country for the impacts of climate change, and lead international efforts to combat and prepare for global warming. The plan proposes actions that would lead to the reduction of GHG by 17% below 2005 levels by 2020. The President also issued a Presidential Memorandum to EPA to continue development of the GHG NSPS regulations for electric generators. The Presidential Memorandum establishes a timeline for the reproposal and issuance of a GHG NSPS for new sources and a timeline for the proposal and final rule for developing carbon pollution standards, regulations, or guidelines for GHG reductions from existing sources under Section 111(d) of the CAA. The Presidential Memorandum further directs EPA to allow the use of “market-based instruments” and “other regulatory flexibilities” to ensure standards will allow for continued reliance on a range of energy sources and technologies and that they are developed and implemented in a manner that provides for reliable and affordable energy and to undertake the rulemaking through direct engagement with states, “as they will play a central role in

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establishing and implementing standards for existing power plants,” and with utility leaders, labor leaders, non-governmental organizations, tribal officials, and other stakeholders.

EPA met the President’s timeline for the reproposal of the GHG NSPS for new sources (under Section 111(b) of the CAA) by releasing the draft rule on September 20, 2013. EPA’s reproposed GHG NSPS for new sources applied only to new fossil-fired EGUs. The reproposed standards, based on the size of the unit, would revise requirements for new fossil-fired utility boilers, integrated gasification combined cycle units, combined and simple cycle turbines, and new sources meeting certain other criteria. New coal-fired facilities would only be able to meet the standard by using partial carbon capture and sequestration technology. The reproposed GHG NSPS removed the blanket exemption for simple-cycle turbines and instead provided an exemption for units that sell to the transmission grid less than one-third of their potential electric output over a three-year rolling average.

The Presidential Memorandum directed EPA to issue the proposed GHG NSPS for modified and existing EGUs by June 1, 2014 and to issue the final rule by June 1, 2015. On June 2, 2014, EPA released the proposed rule under Section 111(d) of the CAA to establish GHG performance standards for existing EGUs. The rule is known as the Clean Power Plan and as proposed would require state-specific CO ₂ emission reduction goals based on EPA’s finding of the best system of emissions reductions (“BSER”). The proposed BSER was based on four “building blocks”: 1) a 6% heat rate improvement to coal-fired generation units; 2) a shift in electrical generation from coal-fired and oil/gas-fired EGUs to natural gas combined cycle units (“NGCCs”) such that the NGCCs would operate at a 70% utilization rate; 3) substitution of fossil fuel generation with renewable resources and new nuclear facilities, and extension of life of about 6% of existing nuclear plants that might be retired; and 4) increases to demand-side energy efficiency programs. Comments on the proposed rule were due on December 1, 2014. PNM submitted comments by the deadline.

Also on June 2, 2014, EPA proposed carbon pollution standards for modified and reconstructed EGUs under Section 111(b). Under the proposed rule there were two alternatives for EGUs: 1) a CO ₂ emission limit based on the unit’s best historic annual CO ₂ emissions plus an additional 2% reduction or 2) an emission limit dependent on when the unit was modified. Sources modified before becoming subject to a section 111(d) plan would be required to meet an emission limit determined by the unit’s best historical annual CO ₂ emission rate plus an additional 2% emission reduction. Units modified after becoming subject to a Section 111(d) plan would be required to meet a unit-specific emission limit determined by the Section 111(b) implementing authority.

On January 7, 2015, EPA announced its intention to propose a federal plan to meet the requirements of the section 111(d) rule, to be released in the summer of 2015 and finalized in summer 2016. EPA also announced changes to the schedule for issuing the final GHG rule regulations for new, modified/reconstructed, and existing EGUs in "Summer 2015." As a result, EPA indicated deadlines for compliance in subsequent years for section 111(d) actions will shift from “June” to “Summer.” EPA initially proposed to issue a final rule for new EGUs by January 8, 2015 and had previously planned to finalize its modified/reconstructed and existing source rules in June 2015. EPA updated the expected deadline for the agency to issue the 111(d) plan to midsummer 2015.

On August 3, 2015, EPA issued its final standards to limit CO ₂ emissions from power plants. Three separate but related actions took place: (1) the final Carbon Pollution Standards for new, modified, and reconstructed power plants were established (under Section 111(b)); (2) the final Clean Power Plan was issued to set standards for carbon emission reductions from existing power plants (under Section 111(d)); and (3) a proposed federal plan associated with the final Clean Power Plan was released.

EPA’s final rule to limit GHG emissions from new, modified, and reconstructed power establishes standards based upon certain, specific conditions. For newly constructed and reconstructed base load natural gas-fired stationary combustion turbines, the EPA is finalizing a standard of 1,000 lb CO ₂ /MWh-gross based on efficient natural gas combined cycled technology as the BSER. Alternatively, owners and operators of base load natural gas-fired combustion turbines may elect to comply with a standard based on an output of 1,030 lb CO ₂ /MWh-net. A new source is any newly constructed fossil fuel-fired power plant that commenced construction after January 8, 2014.

The final standards for coal-fired power plants vary depending on whether the unit is new, modified, or reconstructed. The BSER for new steam units is a supercritical pulverized coal unit with partial carbon capture and storage. Based on that technology, new coal-fired units will be required to meet an emissions standard equal to 1,400 lbs CO ₂ /MWh from the beginning of the power plant’s life. The BSER for modified units is based on each affected unit’s own best potential performance. Standards will be in the form of an emission limit in pounds of CO ₂ per MWh, which will apply to units with modifications resulting in an increase of hourly CO ₂ emissions of more than 10% relative to the emissions of the most recent five years from that unit. The BSER for reconstructed coal-fired power units is the performance of the most efficient generating technology for these types of units. Final emissions standards depend on heat input. Sources with heat input greater than 2,000 MMBTU/hour would be required to meet

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an emission limit of 1,800 lbs CO ₂ /MWh-gross, and sources with a heat input of less than or equal to 2,000 MMBTU/hour would be required to meet an emission limit of 2,000 lbs CO ₂ /MWh-gross.

The final Clean Power Plan rule changed significantly in structure from the June 2014 proposed rule. Changes include delaying the first compliance date by two years from 2020 to 2022; adopting a new approach to calculating the emission targets which resulted in different state goals than those originally proposed; adding a reliability safety valve; and proposing rewards for early reductions. The rule establishes two numeric “emission standards” - one for “fossil-steam” units (coal- and oil-fired units) and one for natural gas-fired units (combined cycle only). The emission standards are based on emission reduction opportunities that EPA deemed achievable using technical assumptions for three “building blocks:” efficiency improvements at coal-fired EGUs, displacement of affected EGUs with renewable energy, and displacement of coal-fired generation with natural gas-fired generation. The final standards are 1,305 lb/MWH for fossil-steam units and 771 lb/MWH for gas units, both of which phase in over the period 2022-2030. To facilitate implementation, EPA converted the emission standards into state goals. Each state’s goal reflects the average state-wide emission rate that all of the state’s affected EGUs would meet in the aggregate if each one achieved the emission standards alone based upon a weighted average of each state’s unique mix of affected units.

Under the final rule, states are required to make initial plan submissions to EPA by September 6, 2016. EPA will grant up to a two-year extension provided that the initial plan meets certain specified criteria for progress and consultation. States receiving an extension must submit an update to EPA in 2017. All final state plans are due by 2018. State plans can be based on either an emission standards (rate or mass) approach or a state measures approach. Under an emission standards approach, federally enforceable emission limits are placed directly on affected units in the state. A state measures approach must meet equivalent rates statewide, but may include some elements, such as renewable energy or energy efficiency requirements, that are not federally enforceable. Plans using state measures may only be used with mass-based goals and must include “backstop” federally enforceable standards for EGUs that will become effective if the state measures fail to achieve the expected level of emission reductions.

The Clean Power Plan also proposes a Clean Energy Incentive Program designed to award credits for early development of certain renewable energy and energy efficiency programs that displace fossil generation in 2020 and 2021 prior to the compliance obligation taking effect in 2022. In addition, the Clean Power Plan contains a reliability safety valve for individual power plants. The reliability safety valve allows for a 90-day relief from CO ₂ emissions limits if generating units need to continue to operate and release excess emissions during emergencies that could compromise electric system reliability.

As discussed above, EPA issued a proposed Federal Plan in association with the Clean Power Plan. Under Section 111(d), EPA is authorized to issue a federal plan for states that do not submit an approvable state plan. EPA indicates that states may voluntarily adopt the Federal Plan in whole or in part as its state plan. EPA explains in its communications that the proposed Federal Plan will be released in advance of the deadline for submission of state plans to provide regulatory certainty to states that fail to submit approvable plan. The proposed Federal Plan will apply emission reduction obligations directly on affected EGUs. The plan presents two approaches: a rate-based emissions trading program and a mass-based emissions trading program. EPA indicates that it will choose only one of these approaches in the final Federal Plan. However, the proposed rule will offer both approaches for states to use as models in their own plans. EPA intends to finalize both the rate-based and mass-based model trading rules in summer 2016.

PNM is currently reviewing the new carbon emission reductions standards set forth for EGUs in EPA’s August 3, 2015 regulatory actions. The Clean Power Plan was published on October 23, 2015. Multiple states, utilities, and trade groups subsequently filed petitions for review and motions to stay in the D.C. Circuit. These actions will impact PNM’s existing and future fossil-fueled EGUs. Impacts could involve investments in additional renewables and energy efficiency programs, efficiency improvements, and/or control technologies at the fossil-fueled EGUs. Under an emissions rate or mass based trading program, PNM may be required to purchase credits or allowances to comply with New Mexico’s final state plan. There are limited efficiency enhancement measures that may be available to a subset of the existing EGUs; however, such measures would provide only marginal GHG improvements. The only emission control technology for coal and gas-fired power plants available for GHG reduction is carbon capture and sequestration, which is not yet a commercially demonstrated technology. Additional GHG control technologies for existing EGUs may become viable in the future. The costs of purchasing carbon credits or allowances, making improvements, or installing new technology could impact the economic viability of some plants. PNM estimates that implementation of the RSIP for BART at SJGS, which requires the installation of SNCRs on Units 1 and 4 by early 2016 and the retirement of SJGS Units 2 and 3 by the end of 2017, should provide a significant step for New Mexico to meet its ultimate compliance with Section 111(d). PNM is unable to predict the impact of this rule on its fossil-fueled generation.

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Federal Legislation

Prospects for enactment of legislation imposing a new or enhanced regulatory program to address climate change in Congress are unlikely in 2015. Instead, EPA continues to be the primary venue for GHG regulation in the near future, especially for coal-fired EGUs. In addition, while there are legislative proposals to limit or block implementation of the Clean Power Plan once it is finalized, enactment of these proposals is highly unlikely.

PNM has assessed, and continues to assess, the impacts of climate change legislation or regulation on its business. This assessment is ongoing and future changes arising out of the legislative or regulatory process could impact the assessment significantly. PNM’s assessment includes assumptions regarding the specific GHG limits, the timing of implementation of these limits, the possibility of a cap-and-trade or tax program including the associated costs and the availability of offsets, the development of technologies for renewable energy and to reduce emissions, and provisions for cost containment. Moreover, the assessment assumes various market reactions such as the price of coal and gas and regional plant economics. These assumptions, at best, are preliminary and speculative. However, based upon these assumptions, the enactment of climate change legislation could, among other things, result in significant compliance costs, including large capital expenditures by PNM, and could jeopardize the economic viability of certain generating facilities. See Note 11. In turn, these consequences could lead to increased costs to customers and affect results of operations, cash flows, and financial condition if the incurred costs are not fully recovered through regulated rates. Higher rates could also contribute to reduced usage of electricity. PNM’s assessment process is ongoing, but too preliminary and speculative at this time for the meaningful prediction of financial impact.

State and Regional Activity

Pursuant to New Mexico law, each utility must submit an IRP to the NMPRC every three years to evaluate renewable energy, energy efficiency, load management, distributed generation, and conventional supply-side resources on a consistent and comparable basis. The IRP is required to take into consideration risk and uncertainty of fuel supply, price volatility, and costs of anticipated environmental regulations when evaluating resource options to meet supply needs of the utility’s customers. The NMPRC requires that New Mexico utilities factor a standardized cost of carbon emissions into their IRPs using prices ranging between $8 and $40 per metric ton of CO ₂ emitted and escalating these costs by 2.5% per year. Under the NMPRC order, each utility must analyze these standardized prices as projected operating costs. Reflecting the developing nature of this issue, the NMPRC order states that these prices may be changed in the future to account for additional information or changed circumstances. Although these prices may not reflect the costs that ultimately will be incurred, PNM is required to use these prices for purposes of its IRP. PNM’s IRP filed with the NMPRC on July 1, 2014 showed that consideration of carbon emissions costs impacted the projected in-service dates of some of the identified resources.

In recent years, New Mexico adopted regulations, which have since been repealed, that would directly limit GHG from larger sources, including EGUs, through a regional GHG cap and trade program and that would cap GHG from larger sources such as EGUs. Although these rules have been repealed, PNM cannot rule out future state legislative or regulatory initiatives to regulate GHG.

On August 2, 2012, thirty-three New Mexico organizations representing public health, business, environmental, consumers, Native American, and other interested parties filed a petition for rulemaking with the NMPRC. The petition asked the NMPRC to issue a NOPR regarding the implementation of an Optional Clean Energy Standard for electric utilities located in New Mexico. The proposed standard would have utilities that elect to participate reduce their CO ₂ emissions by 3% per year. Utilities that opt into the program would be assured recovery of their reasonable compliance costs. On October 4, 2012, the NMPRC held a workshop to discuss the proposed standard and whether it has authority to proceed with the NOPR. On August 28, 2013, the petitioners amended the August 2, 2012 petition and requested that the NMPRC issue a NOPR to implement a “Carbon Risk Reduction Rule” for electric utilities in New Mexico. The proposed rule would require affected utilities to demonstrate a 3% per year CO ₂ emission reduction from a three-year average baseline period between 2005 and 2012. The proposed rule would use a credit system that provides credits for electricity production based on how much less than one metric ton of CO ₂ per MWh the utility emits. Credits would be retired such that 3% per year reductions are achieved from the baseline year until 2035 unless a participating utility elects to terminate the program at the end of 2023. Credits would not expire and could be banked. An advisory committee of interested stakeholders would monitor the program. In addition, utilities would be allowed to satisfy their obligations by funding NMPRC approved energy efficiency programs. There has been no further action on this matter at the NMPRC.

International Accords

The United Nations Framework Convention on Climate Change (“UNFCCC”) is an international environmental treaty that was negotiated at the 1992 United Nations Conference on Environment and Development (informally known as the Earth Summit) and entered into force in March 1994. The objective of the treaty is to “stabilize greenhouse gas concentrations in the

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atmosphere at a level that would prevent dangerous anthropogenic interference with the climate system.” Parties, including the United States, have been meeting annually in Conferences of the Parties (“COP”) to assess progress in meeting the objectives of the UNFCCC. This assessment process led to the negotiation of the Kyoto Protocol in the mid-1990s. The Protocol, which was agreed to in 1997 and established legally binding obligations for developed countries to reduce their GHG emissions, was never ratified by the United States. PNM monitors the proceedings of the UNFCCC, including the annual COP meetings, to determine potential impacts to its business activities. At the COP meeting in 2011, participating nations, including the United States, agreed that in 2015, they would sign an international agreement involving commitment by all nations to begin reducing carbon emissions by 2020. The new agreement, being negotiated by the Ad Hoc Group on the Durban Platform for Enhanced Action, would supplant the Kyoto Protocol. In November 2014, President Obama announced the United States’ commitment to reduce greenhouse gas emissions by 26%-28% from 2005 levels by the year 2025, which would put the United States on a path to achieve economy-wide reductions of around 80% by 2050. As part of the process for developing the new global climate agreement, the United States formally submitted its Intended Nationally Determined Contribution (“INDC”) to the UNFCCC Secretariat on March 31, 2015, which reflected no change from the November 2014 announcement. To date, INDCs have been submitted by nearly 150 nations, including the United States and the European Union. PNM will continue to monitor the United States participation in international accords. However, the Obama administration’s GHG emissions reduction target for the electric utility industry will be based on EPA’s final GHG regulations for new, existing, and modified and reconstructed sources, and PNM believes that implementation of the RSIP for BART at SJGS should provide a significant step towards compliance with the requirements.

Transmission Issues

At any given time, FERC has various notices of inquiry and rulemaking dockets related to transmission issues pending. Such actions may lead to changes in FERC administrative rules or ratemaking policy, but have no time frame in which action must be taken or a docket closed with no further action. Further, such notices and rulemaking dockets do not apply strictly to PNM, but will have industry-wide effects in that they will apply to all FERC-regulated entities. PNM monitors and often submits comments taking a position in such notices and rulemaking dockets or may join in larger group responses. PNM often cannot determine the full impact of a proposed rule and policy change until the final determination is made by FERC and PNM is unable to predict the outcome of these matters.

On November 24, 2009, FERC issued Order 729 approving two Modeling, Data, and Analysis Reliability Standards (“Reliability Standards”) submitted by NERC – MOD-001-1 (Available Transmission System Capability) and MOD-029-1 (Rated System Path Methodology). Both MOD-001-1 and MOD-029-1 require a consistent approach, provided for in the Reliability Standards, to measuring the total transmission capability (“TTC”) of a transmission path. The TTC level established using the two Reliability Standards could result in a reduction in the available transmission capacity currently used by PNM to deliver generation resources necessary for its jurisdictional load and for fulfilling its obligations to third-party users of the PNM transmission system.

During the first quarter of 2011, at the request of PNM and other southwestern utilities, NERC advised all transmission owners and transmission service providers that the implementation of portions of the MOD-029 methodology for “Flow Limited” paths has been delayed until such time as a modification to the standard can be developed that will mitigate the technical concerns identified by the transmission owners and transmission service providers. PNM and other western utilities filed a Standards Action Request with NERC in the second quarter of 2012.

NERC initiated an informal development process to address directives in Order 729 to modify certain aspects of the MOD standards, including MOD-001 and MOD-029. The modifications to this standard would retire MOD-029 and require each transmission operator to determine and develop methodology for TTC values for MOD-001.

A final ballot for MOD-001-2 concluded on December 20, 2013 and received sufficient affirmative votes for approval. On February 10, 2014, NERC filed with FERC a petition for approval of MOD-001-2 and retirement of reliability standards MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a, and MOD-030-2. On June 19, 2014, FERC issued a NOPR to approve a new reliability standard. The MOD-001-2 standard will become effective on the first day of the calendar quarter that is 18 months after the date the standard is approved by FERC. MOD-001-2 will replace multiple existing reliability standards and will remove the risk of reduced TTC for PNM and other western utilities.

In July 2011, FERC issued Order 1000 adopting new requirements for transmission planning, cost allocation, and development for significant transmission planning related changes. In response, PNM and WestConnect (an organization of utility companies providing transmission of electricity in the western region that includes PNM) participants filed modified versions to their transmission tariff’s Attachment K (Transmission Planning Process). In March 2013, FERC issued its order regarding PNM’s

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and six other WestConnect FERC jurisdictional utilities’ compliance filings partially accepting many aspects of the filings. A major change directed by FERC is the requirement that the cost allocations be binding on identified beneficiaries and that a process be created that will result in a qualified developer being selected. On September 20, 2013, PNM and the other WestConnect FERC jurisdictional entities submitted their revised regional compliance filings to address and comply with the March 2013 FERC order.

In September 2014, FERC issued an additional order concerning the regional planning process and cost allocation in response to the September 2013 compliance filings. The FERC order required the WestConnect entities to make another compliance filing to hold a single year “abbreviated planning process for year 2015.” The order also required the entities to file the WestConnect “Planning Participation Agreement.” Of significant concern to FERC jurisdictional entities in this order was FERC’s ruling that the non-jurisdictional entities would not be required to participate in cost allocation on regional projects, which the WestConnect FERC jurisdictional entities believe does not comport with FERC’s Order 1000 position on the “cost causation principle” and could create a “free rider-ship” issue for certain participants in the planning process. Due to the cost allocation issue, FERC-regulated entities jointly filed a request for re-hearing or clarification of the FERC order in October 2014. The FERC-regulated entities filed compliance filings regarding the September 2014 FERC order in November 2014, making several adjustments to the language in their respective Attachment Ks, as well as a separate unsigned version of the proposed final version of the Planning Participation Agreement. In May 2015, FERC conditionally accepted the November 2014 filings, but denied the re-hearing request filed in October 2014. The WestConnect FERC jurisdictional entities made compliance filings regarding the May 2015 FERC order on June 16, 2015, making several adjustments to the language in their respective Attachment K.

In July 2013, the WestConnect participants submitted their cost allocation and inter-regional coordination plan between WestConnect and three other planning regions. In December 2014, FERC issued an order conditionally accepting the WestConnect compliance filing including the California Independent System Operator Corporation (“CAISO”), Northern Tier Transmission Group Applicants, and Columbia Grid (collectively the “Western Filing Parties”). The order required the Western Filing Parties to use the same method for determining the regional benefits of a proposed interregional transmission facility through revisions to the common tariff language. Without requiring modification to the common tariff language for all four Western planning regions, CAISO would tender revised tariff sheets to address the Western Filing Parties compliance condition. The WestConnect entities and the other Western Filing Parties submitted a common compliance filing on February 17, 2015, stating that CAISO had agreed to change its Open Access Transmission Tariff language and, therefore, the other entities would not have to change the common OATT language.

As of January 2015, all of the WestConnect jurisdictional entities have executed the Planning Participation Agreement and some of the non-jurisdictional entities have also signed. A 2015 study plan has been completed and committee activities are currently focused on establishing the data for the technical models, production cost models and base system to be used as the reference for the 2015 study work. WestConnect has hired a consultant to complete the single year planning study for 2015 as required in the September 2014 FERC order.

Financial Reform Legislation

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Reform Act”), enacted in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading facility. It also includes provisions related to swap transaction reporting and record keeping and may impose margin requirements on swaps that are not centrally cleared. The United States Commodity Futures Trading Commission (“CFTC”) has published final rules defining several key terms related to the act and has set compliance dates for various types of market participants. The Dodd-Frank Reform Act provides exemptions from certain requirements, including an exception to the mandatory clearing and swap facility execution requirements for commercial end-users that use swaps to hedge or mitigate commercial risk. PNM has elected the end-user exception to the mandatory clearing requirement. PNM expects to be in compliance with the Dodd-Frank Reform Act and related rules within the time frames required by the CFTC. However, as a result of implementing and complying with the Dodd-Frank Reform Act and related rules, PNM’s swap activities could be subject to increased costs, including from higher margin requirements. At this time, PNM cannot predict the ultimate impact the Dodd-Frank Reform Act may have on PNM’s financial condition, results of operations, cash flows, or liquidity.

Other Matters

As discussed under Employees in Item 1. of the 2014 Annual Reports on Form 10-K, at December 31, 2014, PNM had 593 employees in its power plant and operations areas that were covered by a collective bargaining agreement with the IBEW Local 611 that was entered into in July 2012 and was to expire as of May 1, 2015. Negotiations for a new agreement with the

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IBEW began in January 2015 and the parties agreed to extend the collective bargaining agreement should an agreement not be reached by May 1, 2015. The agreement continued in effect during negotiations unless either the union or PNM gave a thirty days' written notice of termination. On July 22, 2015, PNM gave notice of termination, effective August 24, 2015. PNM and the union continue to negotiate a new agreement. While the Company is optimistic that an agreement will be reached, PNM cannot, at this time, predict the outcome of the negotiations. PNM is currently working on contingency planning for certain scenarios that may occur as a result of negotiations and contract termination. The wages and benefits for all PNM employees who are members of the IBEW are typically included in the rates charged to electric customers, subject to approval of the NMPRC.

On March 25, 2013, a petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for utility workers. On April 12, 2013, a second petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to certify a union at TNMP for meter technicians, who were not included in the original petition. Approximately 200 employees were covered by the petitions. Elections to determine whether the IBEW would represent the employees were held in May 2013. The employees voted to unionize through both petitions and contract negotiations began. Subsequently, on June 25, 2013, a third petition was filed by IBEW Local 66 with the National Labor Relations Board seeking to include a group of three relay technicians, who were not included in the original petition. In August 2013, the relay technicians voted to unionize. As of December 31, 2014, TNMP had 195 employees represented by IBEW Local 66. In January 2015, a decertification election was held for those employees covered by the original petition. The employees voted to retain union representation. The parties reached an agreement and union members ratified the agreement on February 28, 2015. The agreement is in effect from March 9, 2015 through September 9, 2016.

See Notes 11 and 12 herein and Notes 16 and 17 of the Notes to Consolidated Financial Statements in the 2014 Annual Reports on Form 10-K for a discussion of commitments and contingencies and rate and regulatory matters.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in accordance with GAAP requires Company management to select and apply accounting policies that best provide the framework to report the results of operations and financial position for PNMR, PNM, and TNMP. The selection and application of those policies requires management to make difficult, subjective, and/or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions.

As of September 30, 2015 , there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2014 Annual Reports on Forms 10-K. The policies disclosed included unbilled revenues, regulatory accounting, impairments, decommissioning and reclamation costs, derivatives, pension and other postretirement benefits, accounting for contingencies, income taxes, and market risk.

MD&A FOR PNM

RESULTS OF OPERATIONS

PNM operates in only one reportable segment, as presented above in Results of Operations for PNMR.

MD&A FOR TNMP

RESULTS OF OPERATIONS

TNMP operates in only one reportable segment, as presented above in Results of Operations for PNMR.

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

Statements made in this filing that relate to future events or PNMR’s, PNM’s, or TNMP’s expectations, projections, estimates, intentions, goals, targets, and strategies are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and estimates. PNMR, PNM, and TNMP assume no obligation to update this information.

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Because actual results may differ materially from those expressed or implied by these forward-looking statements, PNMR, PNM, and TNMP caution readers not to place undue reliance on these statements. PNMR’s, PNM’s, and TNMP’s business, financial condition, cash flows, and operating results are influenced by many factors, which are often beyond their control, that can cause actual results to differ from those expressed or implied by the forward-looking statements. These factors include:


•	The ability of PNM and TNMP to recover costs and earn allowed returns in regulated jurisdictions, including the impact of federal or state regulatory and judicial action with regard to the proposed early retirement of SJGS Units 2 and 3


•	Uncertainty regarding obtaining required regulatory approvals, and the timing of such approvals, for the final restructuring, coal supply, and related agreements for SJGS, which are necessary for operational and future environmental compliance matters, in order for the agreements to become effective, as well as the closing of the sale of SJCC


•	Uncertainty surrounding the status of PNM’s participation in jointly-owned generation projects resulting from the scheduled expiration of the operational agreements for SJGS and Four Corners, as well as the currently effective coal supply agreement for SJGS


•	The impacts on the electricity usage of customers and consumers due to performance of state, regional, and national economies, mandatory energy efficiency measures, weather, seasonality, alternative sources of power, and other changes in supply and demand, including the failure to maintain or replace customer contracts on favorable terms


•	State and federal regulation or legislation relating to environmental matters, including the RSIP for SJGS’s compliance with the CAA, the resultant costs of compliance, and other impacts on the operations and economic viability of PNM’s generating plants


•	The ability of the Company to successfully forecast and manage its operating and capital expenditures


•	The risks associated with completion of generation, transmission, distribution, and other projects


•	Physical and operational risks related to climate change and potential financial risks resulting from climate change litigation and legislative and regulatory efforts to limit GHG, including the federal Clean Power Plan


•	Uncertainty regarding the requirements and related costs of decommissioning power plants and reclamation of coal mines supplying certain power plants, as well as the ability to recover those costs from customers


•	The performance of generating units, transmission systems, and distribution systems, which could be negatively affected by operational issues, fuel quality, unplanned outages, extreme weather conditions, terrorism, cybersecurity breaches, and other catastrophic events


•	Employee workforce factors, including issues arising out of collective bargaining agreements and labor negotiations with union employees


•	Variability of prices and volatility and liquidity in the wholesale power and natural gas markets


•	Changes in price and availability of fuel and water supplies, including the ability of the mines supplying coal to PNM’s coal-fired generating units and the companies involved in supplying nuclear fuel to provide adequate quantities of fuel


•	Changes in technology, particularly with respect to new and alternative sources of energy, advanced grid technology, and cybersecurity


•	State and federal regulatory, legislative, and judicial decisions and actions on ratemaking, tax, and other matters


•	Regulatory, financial, and operational risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainties


•	Adverse outcomes of legal or regulatory proceedings, including the extent of insurance coverage


•	The Company’s ability to access the financial markets, including disruptions in the credit markets, actions by ratings agencies, and fluctuations in interest rates


•	The potential unavailability of cash from PNMR’s subsidiaries due to regulatory, statutory, or contractual restrictions


•	The risk that FERC rulemakings may negatively impact the operation of PNM’s transmission system


•	The impacts of decreases in the values of marketable equity securities maintained to provide for decommissioning, reclamation, pension benefits, and other postretirement benefits


•	Counterparty credit and performance risk and the effectiveness of risk management


•	Changes in applicable accounting principles or policies

Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, and TNMP’s 2014 Annual Reports on Form 10-K are disclosed in Item 1A, Risk Factors, in Part II of this Form 10-Q.

For information about the risks associated with the use of derivative financial instruments, see Item 3. “Quantitative and Qualitative Disclosures About Market Risk.”

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SECURITIES ACT DISCLAIMER

Certain securities described or cross-referenced in this report have not been registered under the Securities Act of 1933, as amended, or any state securities laws and may not be reoffered or sold in the United States absent registration or an applicable exemption from the registration requirements of the Securities Act of 1933 and applicable state securities laws. This Form 10-Q does not constitute an offer to sell or the solicitation of an offer to buy any securities.

WEBSITES

The PNMR website, www.pnmresources.com , is an important source of Company information. New or updated information for public access is routinely posted. PNMR encourages analysts, investors, and other interested parties to register on the website to automatically receive Company information by e-mail. This information includes news releases, notices of webcasts, and filings with the SEC. Participants will not receive information that was not requested and can unsubscribe at any time.

Our Internet addresses are:


•	PNMR: www.pnmresources.com


•	PNM: www.pnm.com


•	TNMP: www.tnmp.com

In addition to the corporate websites, PNM has a website, www.PowerforProgress.com , dedicated to showing how it balances delivering reliable power at affordable prices and protecting the environment. This website is designed to be a resource for the facts about PNM’s operations and support efforts, including plans for building a sustainable energy future for New Mexico. The contents of these websites are not a part of this Form 10-Q. The SEC filings of PNMR, PNM, and TNMP, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are accessible free of charge on the PNMR website as soon as reasonably practicable after they are filed with, or furnished to, the SEC. These reports are also available in print upon request from PNMR free of charge.

Also available on the Company’s website at www.pnmresources.com/corporate-governance.aspx and in print upon request from any shareholder are our:


•	Corporate Governance Principles


•	Code of Ethics ( Do the Right Thing – Principles of Business Conduct )


•	Charters of the Audit and Ethics Committee, Nominating and Governance Committee, Compensation and Human Resources Committee, and Finance Committee

The Company will post amendments to or waivers from its code of ethics (to the extent applicable to the Company’s executive officers and directors) on its website.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company manages the scope of its various forms of risk through a comprehensive set of policies and procedures with oversight by senior level management through the RMC. The Board’s Finance Committee sets the risk limit parameters. The RMC has oversight over the risk control organization. The RMC is assigned responsibility for establishing and enforcing the policies, procedures, and limits and evaluating the risks inherent in proposed transactions on an enterprise-wide basis. The RMC’s responsibilities include:


•	Establishing policies regarding risk exposure levels and activities in each of the business segments


•	Approving the types of derivatives entered into for hedging


•	Reviewing and approving hedging risk activities


•	Establishing policies regarding counterparty exposure and limits


•	Authorizing and delegating transaction limits


•	Reviewing and approving controls and procedures for derivative activities


•	Reviewing and approving models and assumptions used to calculate mark-to-market and market risk exposure


•	Proposing risk limits to the Board’s Finance Committee for its approval

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•	Quarterly reporting to the Board’s Audit and Finance Committees on these activities

To the extent an open position exists, fluctuating commodity prices, interest rates, equity prices, and economic conditions can impact financial results and financial position, either favorably or unfavorably. As a result, the Company cannot predict with certainty the impact that its risk management decisions may have on its businesses, operating results, or financial position.

Commodity Risk

Information concerning accounting for derivatives and the risks associated with commodity contracts is set forth in Note 7, including a summary of the fair values of mark-to-market energy related derivative contracts included in the Condensed Consolidated Balance Sheets. During the nine months ended September 30, 2015 and the year ended December 31, 2014, the Company had no commodity derivative instruments designated as cash flow hedging instruments.

Commodity contracts, other than those that do not meet the definition of a derivative under GAAP, and those derivatives designated as normal purchases and normal sales, are recorded at fair value on the Condensed Consolidated Balance Sheets. The following table details the changes in PNMR’s net asset or liability balance sheet position for mark-to-market energy transactions.



	Nine Months Ended
	September 30,
	2015			2014
Economic Hedges	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	9,546		$	3,273
Amount realized on contracts delivered during period	(8,379		)	2,005
Changes in fair value	7,127			(1,938		)
Net mark-to-market change recorded in earnings	(1,252		)	67
Net change recorded as regulatory assets and liabilities	235			(166		)
Net fair value at end of period	$	8,529		$	3,174

The following table provides the maturity of PNMR's net assets (liabilities), giving an indication of when these mark-to-market amounts will settle and generate (use) cash.

Fair Value of Mark-to-Market Instruments at September 30, 2015



	Settlement Dates
	2015		2016		2017
	(In thousands)
Economic hedges
Prices actively quoted	$	—	$	—	$	—
Prices provided by other external sources	3,297		2,604		2,628
Prices based on models and other valuations	—		—		—
Total	$	3,297	$	2,604	$	2,628

PNM measures the market risk of its long-term contracts and wholesale activities using a Monte Carlo VaR simulation model to report the possible loss in value from price movements. VaR is not a measure of the potential accounting mark-to-market loss. The quantitative risk information is limited by the parameters established in creating the model. The Monte Carlo VaR methodology employs the following critical parameters: historical volatility estimates, market values of all contractual commitments, a three-day holding period, seasonally adjusted and cross-commodity correlation estimates, and a 95% confidence level. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used.

PNM measures VaR for the positions in its wholesale portfolio (not covered by the FPPAC). For the nine months ended September 30, 2015 , the high, low, and average VaR amounts were $2.6 million, $0.9 million, and $1.5 million. For the year

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ended December 31, 2014 , the high, low, and average VaR amounts were $2.1 million, $0.6 million, and $0.9 million. At September 30, 2015 and December 31, 2014 , the VaR amounts for the PNM wholesale portfolio were $1.1 million and $1.3 million.

The VaR limits, which were not exceeded during the nine months ended September 30, 2015 or the year ended December 31, 2014 , represent an estimate of the potential gains or losses that could be recognized on the Company’s portfolios, subject to market risk, given current volatility in the market, and are not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market prices, operating exposures, and the timing thereof, as well as changes to the underlying portfolios during the year.

Credit Risk

The Company is exposed to credit risk from its retail and wholesale customers, as well as the counterparties to derivative instruments. The Company conducts counterparty risk analysis across business segments and uses a credit management process to assess the financial conditions of counterparties. The following table provides information related to PNMR’s credit exposure by the credit worthiness (credit rating) and concentration of credit risk for counterparties to derivative transactions. All credit exposures at September 30, 2015 will mature in less than two years, except for $0.7 million, which will mature in the fourth quarter of 2017.

Schedule of Credit Risk Exposure

September 30, 2015



Rating ⁽¹⁾	Credit Risk Exposure ⁽²⁾		Number of Counter-parties >10%	Net Exposure of Counter-parties >10%
	(Dollars in thousands)
External ratings:
Investment grade	$	3,515	1	$	2,916
Non-investment grade	—		—	—
Internal ratings:
Investment grade	6,520		1	5,729
Non-investment grade	9		—	—
Total	$	10,044		$	8,645


⁽¹⁾	The rating “Investment Grade” is for counterparties, or a guarantor, with a minimum S&P rating of BBB- or Moody’s rating of Baa3. The category “Internal Ratings – Investment Grade” includes those counterparties that are internally rated as investment grade in accordance with the guidelines established in the Company’s credit policy.

⁽²⁾

The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than firm-requirements wholesale customers), forward sales, and short-term sales. The exposure captures the amounts from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses. Gross exposures can be offset according to legally enforceable netting arrangements but are not reduced by posted credit collateral. At September 30, 2015 , PNMR held $0.1 million of cash collateral to offset its credit exposure.

Net credit risk for the Company’s largest counterparty as of September 30, 2015 was $5.7 million.

The PVNGS lessor notes are not exposed to credit risk, since the notes are repaid as PNM makes payments on the underlying leases. Other investments have no significant counterparty credit risk.

Interest Rate Risk

The majority of the Company’s long-term debt is fixed-rate debt and does not expose earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of PNMR’s consolidated long-term debt instruments would increase by 2.1%, or $47.6 million, if interest rates were to decline by 50 basis points from their levels at September 30, 2015 . In general, an increase in fair value would impact earnings and cash flows to the extent not recoverable in rates if all or a portion of debt instruments were acquired in the open market prior to their maturity. At October 23, 2015 , PNMR, PNM, and TNMP had

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short-term debt outstanding of none, none, and $20.0 million under their revolving credit facilities, which allow for a maximum aggregate borrowing capacity of $300.0 million for PNMR, $400.0 million for PNM, and $75.0 million for TNMP. PNM had no borrowings outstanding under its $50.0 million PNM New Mexico Credit Facility at October 23, 2015 . The revolving credit facilities, the PNM New Mexico Credit Facility, the $125.0 million PNM Multi-draw Term Loan, the $100.0 million PNMR Term Loan Agreement, and the PNMR 2015 Term Loan Agreement bear interest at variable rates, which averaged 1.19% for the TNMP Revolving Credit Facility, 0.78% for the PNM Multi-draw Term Loan, 1.05% for the PNMR Term Loan Agreement, and 1.20% for the PNMR 2015 Term Loan Agreement on October 23, 2015 , and the Company is exposed to interest rate risk to the extent of future increases in variable interest rates.

The investments held by PNM in trusts for decommissioning and reclamation had an estimated fair value of $242.8 million at September 30, 2015 , of which 45.8% were fixed-rate debt securities that subject PNM to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 50 basis points from their levels at September 30, 2015 , the decrease in the fair value of the fixed-rate securities would be 3.4%, or $3.8 million.

PNM does not directly recover or return through rates any losses or gains on the securities, including equity investments discussed below, in the trusts for decommissioning and reclamation. However, the overall performance of these trusts does enter into the periodic determinations of expense and funding levels, which are factored into the rate making process to the extent applicable to regulated operations. PNM is at risk for shortfalls in funding of obligations due to investment losses, including those from the equity market risks discussed below to the extent not ultimately recovered through rates charged to customers.

Equity Market Risk

The investments held by PNM in trusts for decommissioning and reclamation include certain equity securities at September 30, 2015 . These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 42.4% of the securities held by various trusts as of September 30, 2015 . A hypothetical 10% decrease in equity prices would reduce the fair values of these funds by $10.3 million.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

As of the end of the period covered by this quarterly report, each of PNMR, PNM, and TNMP conducted an evaluation under the supervision and with the participation of its management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934). Based upon this evaluation, the Chief Executive Officer and the Chief Financial Officer of each of PNMR, PNM, and TNMP concluded that the disclosure controls and procedures are effective.

Changes in internal controls

There have been no changes in each of PNMR’s, PNM’s, and TNMP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended September 30, 2015 that have materially affected, or are reasonably likely to materially affect, each of PNMR’s, PNM’s, and TNMP’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Notes 11 and 12 for information related to the following matters, for PNMR, PNM, and TNMP, incorporated in this item by reference.

Note 11


•	The Clean Air Act – Regional Haze – SJGS


•	The Clean Air Act – Regional Haze – Four Corners


•	The Clean Air Act – Citizen Suit Under the Clean Air Act


•	The Clean Air Act – Four Corners Clean Air Act Lawsuit


•	Four Corners Coal Mine

113


•	WEG v. OSM NEPA Lawsuit


•	Navajo Nation Environmental Issues


•	Santa Fe Generating Station


•	Continuous Highwall Mining Royalty Rate


•	Four Corners Severance Tax Assessment


•	PVNGS Water Supply Litigation


•	San Juan River Adjudication


•	Rights-of-Way Matter


•	Complaint Against Southwestern Public Service Company


•	Navajo Nation Allottee Matters

Note 12


•	PNM – New Mexico General Rate Case


•	PNM – Proceeding Regarding Definition of Future Test Year


•	PNM – Renewable Portfolio Standard


•	PNM – Renewable Energy Rider


•	PNM – Energy Efficiency and Load Management


•	PNM – Integrated Resource Plan


•	PNM – San Juan Generating Station Units 2 and 3 Retirement


•	PNM – Application for Certificate of Convenience and Necessity


•	PNM – Formula Transmission Rate Case


•	PNM – Firm-Requirements Wholesale Customers - Navopache Electric Cooperative, Inc.


•	TNMP – Advanced Meter System Deployment


•	TNMP – Energy Efficiency


•	TNMP – Transmission Cost of Service Rates

See also Climate Change Issues under Other Issues Facing the Company in MD&A. The third paragraph under State and Regional Activity is incorporated in this item by reference.

ITEM 1A. RISK FACTORS

As of the date of this report, there have been no material changes with regard to the Risk Factors disclosed in PNMR’s, PNM’s, and TNMP’s Annual Reports on Form 10-K for the year ended December 31, 2014 .

ITEM 6. EXHIBITS



3.1	PNMR	Articles of Incorporation of PNMR, as amended to date (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed November 21, 2008)

3.2	PNM	Restated Articles of Incorporation of PNM, as amended through May 31, 2002 (incorporated by reference to Exhibit 3.1.1 to PNM’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002)

3.3	TNMP	Articles of Incorporation of TNMP, as amended through July 7, 2005 (incorporated by reference to Exhibit 3.1.2 to TNMP’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

3.4	PNMR	Bylaws of PNMR, with all amendments to and including February 26, 2015 (incorporated by reference to Exhibit 3.4 to PNMR’s Annual Report on Form 10-K for the year ended December 31, 2014)

3.5	PNM	Bylaws of PNM, with all amendments to and including May 31, 2002 (incorporated by reference to Exhibit 3.1.2 to PNM’s Report on Form 10-Q for the fiscal quarter ended June 30, 2002)

3.6	TNMP	Bylaws of TNMP, with all amendments to and including June 18, 2013 (incorporated by reference to Exhibit 3.6 to TNMP’s Current Report on Form 8-K filed June 20, 2013)

10.1	PNM	Coal Supply Agreement dated July 1, 2015 between Westmoreland Coal Company and PNM

10.2	PNM	Underground Coal Sales Agreement Termination and Mutual Release Agreement dated July 1, 2015 among San Juan Coal Company, BHP Billiton New Mexico Coal, Inc., PNM, and Tucson Electric Coal Company

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10.3	PNM	San Juan Project Restructuring Agreement executed as of July 31, 2015 among PNM, Tucson Electric Coal Company, The City of Farmington, New Mexico, M-S-R Public Power Agency, The Incorporated County of Los Alamos, New Mexico, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power Systems, Tri-State Generation and Transmission Association, Inc., and PNMR Development and Management Corporation

10.4	PNM	Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of July 31, 2015 among PNM, Tucson Electric Power Company, The City of Farmington, New Mexico, M-S-R Public Power Agency, The Incorporated County of Los Alamos, New Mexico, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power Systems, Tri-State Generation and Transmission Association, Inc., and PNMR Development and Management Corporation

10.5	PNM	Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement made as of July 31, 2015 among PNM, Tucson Electric Power Company, The City of Farmington, New Mexico, The Incorporated County of Los Alamos, New Mexico, Utah Associated Municipal Power Systems, and PNMR Development and Management Corporation

10.6	PNMR	Fourth Amendment to Credit Agreement dated September 9, 2015 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent

10.7	PNMR	First Amendment to Term Loan Agreement dated September 9, 2015 among PNMR, the lenders party thereto, and Wells Fargo Bank, National Association, as administrative agent

12.1	PNMR	Ratio of Earnings to Fixed Charges

12.2	PNM	Ratio of Earnings to Fixed Charges

12.3	TNMP	Ratio of Earnings to Fixed Charges

31.1	PNMR	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	PNMR	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.3	PNM	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.4	PNM	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.5	TNMP	Chief Executive Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.6	TNMP	Chief Financial Officer Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	PNMR	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2	PNM	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.3	TNMP	Chief Executive Officer and Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

101.INS	PNMR, PNM, and TNMP	XBRL Instance Document

101.SCH	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Schema Document

101.CAL	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	PNMR, PNM, and TNMP	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.



		PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO TEXAS-NEW MEXICO POWER COMPANY
		(Registrants)


Date:	October 30, 2015	/s/ Joseph D. Tarry
		Joseph D. Tarry
		Vice President and Corporate Controller
		(Officer duly authorized to sign this report)

116

EXECUTION VERSION

Coal Supply Agreement

By and Between

Westmoreland Coal Company

and

Public Service Company of New Mexico

TABLE OF CONTENTS

Page



ARTICLE I	DEFINITIONS	1

Section 1.1	Capital Costs	1
Section 1.2	CCR Disposal Agreement	1
Section 1.3	Coal Leases	2
Section 1.4	Contract Year	2
Section 1.5	Fruitland Coal Sublease	2
Section 1.6	Guaranty	2
Section 1.7	Mineable Coal	2
Section 1.8	Non-SJCC Coal	2
Section 1.9	Preexisting Stockpile Coal	3
Section 1.10	Processed Coal	3
Section 1.11	Prudent Mining Practices	3
Section 1.12	Quarterly Price Adjustment	3
Section 1.13	Raw Coal	3
Section 1.14	Reclamation Services Agreement	3
Section 1.15	Reduced Price	3
Section 1.16	Reserve of Coal	4
Section 1.17	SJCC Environmental Force Majeure Price	4
Section 1.18	SJCC Site Area	4
Section 1.19	San Juan Station	4
Section 1.20	SPA	4
Section 1.21	Tier 1 Price	5
Section 1.22	Tier 2 Price	5
Section 1.23	Tier 1 Tons	5
Section 1.24	Tier 2 Tons	5
Section 1.25	Ton	5
Section 1.26	Ute ROW	5
Section 1.27	Definitions of Other Terms	6

ARTICLE II	OBLIGATIONS OF THE PARTIES AND TERM OF THE AGREEMENT	8

Section 2.1	Obligations of SJCC	8
Section 2.2	Obligations of Utility	9
Section 2.3	Term	9
Section 2.4	Guaranty	9
Section 2.5	Extension	10
Section 2.6	Representations and Warranties	10

ARTICLE III	COAL SUPPLY	10

Section 3.1	Ownership of Coal	10

ARTICLE IV	DELIVERY OF COAL	11

Section 4.1	Delivery Obligation	11
Section 4.2	Delivery of Coal	11

- i -

TABLE OF CONTENTS

(continued)

Page



Section 4.3	Delivery Rates	11
Section 4.4	Utility’s Coal Storage	12
Section 4.5	Reserve of Coal	12

ARTICLE V	COAL SPECIFICATIONS AND WEIGHING, SAMPLING, AND ANALYSIS	12

Section 5.1	Coal Size	12
Section 5.2	Coal Quality	12
Section 5.3	Weighing and Analysis Facilities and Methods	13

ARTICLE VI	COAL LEASES, LAND, AND LAND RIGHTS	13

Section 6.1	Dedicated Reserves	13
Section 6.2	SJCC’s Facilities	13
Section 6.3	Utility’s Rights Vis-a-Vis the SJCC Site Area	14
Section 6.4	CCR Disposal Area	14
Section 6.5	Compliance with Leases and Other Instruments	14
Section 6.6	Restrictions on SJCC	15
Section 6.7	Site Area Lease Management	15
Section 6.8	Reclamation Services Agreement and CCR Disposal Agreement Coordination	15

ARTICLE VII	OPERATIONS	16

Section 7.1	Mining Plans and Methods	16
Section 7.2	Annual Operating Plan	16
Section 7.3	Processing Methods	18
Section 7.4	Reclamation Activities	19

ARTICLE VIII	SJCC COMPENSATION	19

Section 8.1	Compensation Components	19
Section 8.2	Payment of the Utility Payment Stream	20
Section 8.3	Substitute REI	23
Section 8.4	Payments under the Ute ROW	24
Section 8.5	Gas Wells	24
Section 8.6	Reclamation Bond Premium	24
Section 8.7	Invoicing, Monthly Reports and Settlement	24

ARTICLE IX	MINING OVERSIGHT COMMITTEE	27

Section 9.1	Purpose	27
Section 9.2	Mining Oversight Committee Members	27
Section 9.3	Procedures and Practices	27
Section 9.4	Mining Oversight Committee Decisions	28
Section 9.5	Relationship to Joint Committee and Arbitration	28

ARTICLE X	JOINT COMMITTEE	28

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TABLE OF CONTENTS

(continued)

Page



Section 10.1	Purpose	28
Section 10.2	Designation	28
Section 10.3	Authority	28
Section 10.4	Decisions by the Joint Committee	29
Section 10.5	Relationship to Arbitration	29

ARTICLE XI	DISPUTE RESOLUTION	29

Section 11.1	Matters To Be Arbitrated; Notice of Claims and Defenses; Party Arbitrator Designation	29
Section 11.2	Arbitrators; Selection of Neutral Arbitrator	30
Section 11.3	Arbitration Hearings, Procedures and Timing	30
Section 11.4	Choice of Law	30
Section 11.5	Award and Enforcement	30
Section 11.6	Performance Pending Arbitration Decision	30

ARTICLE XII	FORCE MAJEURE, NON-NORMAL CONDITIONS, RIGHTS TO CURE, TERMINATION AND EXPIRATION	31

Section 12.1	Force Majeure and Environmental Force Majeure	31
Section 12.2	Non-Normal Conditions, Right to Cure, and Offers of Non-SJCC Coal	35
Section 12.3	SJCC Default	37
Section 12.4	Utility Default	39
Section 12.5	Utility’s Purchase Right Upon Expiration of the Term	40
Section 12.6	Termination and Remedy	41
Section 12.7	Termination Remedies in the Event of Extension Term	42

ARTICLE XIII	INDEMNITY	42

Section 13.1	General Indemnification	42

ARTICLE XIV	GENERAL PROVISIONS	43

Section 14.1	Compliance with Applicable Laws	43
Section 14.2	Labor Force	43
Section 14.3	Confidentiality / Non-disclosure	44
Section 14.4	Permits and Approvals	44
Section 14.5	Waivers	45
Section 14.6	Insurance	45
Section 14.7	Notices	45
Section 14.8	Choice of Law	46
Section 14.9	Assignment	46
Section 14.10	Successors and Assigns	46
Section 14.11	Authorizations	46
Section 14.12	Amendments	46
Section 14.13	Construction	47
Section 14.14	Entire Agreement	47

- iii -

TABLE OF CONTENTS

(continued)

Page



Section 14.15	Limitation on Damages	47
Section 14.16	Severability	47
Section 14.17	Survival of Provisions	47
ARTICLE XV	SIGNATURES	48

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Coal Supply Agreement

Exhibits and Attachments

Attachment 1 Form of Guaranty

Exhibit A Coal Leases

Exhibit B Delivery Points

Exhibit C Mining Plans and Methods

Exhibit D Projected Annual Tonnage

Exhibit E SJCC Site Area

Exhibit F SJCC Insurance Requirements

Exhibit G First Year Approved Annual Operating Plan

Exhibit H Coal Quality Measures

Exhibit I Taxes and Royalties

Exhibit J Purchase Price Adjustment Factors (Utility Event Of Default)

Exhibit K Purchase Price Adjustment Factors (Environmental Force Majeure)

Exhibit L Purchase Price Adjustment Factors (SJCC Event Of Default)

Exhibit M Allocation Methodology For Annual Preexisting Stockpile Amount

Exhibit N Quarterly Price Adjustment

Exhibit O Form of Assignment and Assumption of Coal Supply Agreement

- v -

Coal Supply Agreement

Parties and Recitals

THIS COAL SUPPLY AGREEMENT (“Agreement”) is dated July 1, 2015 between WESTMORELAND COAL COMPANY , a Delaware corporation (“Westmoreland”) and PUBLIC SERVICE COMPANY OF NEW MEXICO , a New Mexico corporation (“Utility”), (with Westmoreland and Utility herein sometimes being referred to herein individually as “Party” and collectively as “Parties”).

WHEREAS , pursuant to the SPA (as hereinafter defined), Westmoreland will acquire, as of the date of “Closing” under the SPA, one hundred percent (100%) of the issued and outstanding shares of San Juan Coal Company, a Delaware corporation (“SJCC”), and San Juan Transportation Company, a Delaware corporation (“SJTC”);

WHEREAS , SJCC holds certain coal leases and surface rights known as the Coal Leases which are more particularly described in Exhibit A ;

WHEREAS , Utility owns, in part, a coal-burning power plant in the vicinity of the Coal Leases;

WHEREAS , the San Juan Station (as hereinafter defined) currently consists of four generating units, two of which will be retired as described in Section 1.19 ;

WHEREAS , Utility desires to purchase, and SJCC to sell, coal that has been mined from an underground coal mine on the Coal Leases and delivered to the delivery point(s) shown on Exhibit B and SJCC is willing to undertake such obligation upon the terms and conditions hereinafter set forth;

WHEREAS , SJCC shall provide coal pursuant to this Agreement in a manner consistent with the processes and quality described herein; and

WHEREAS , the purpose of this Agreement is to set forth the agreement between the Parties relating to the supply of coal by SJCC to the San Juan Station.

NOW, THEREFORE , in consideration of the terms, covenants and agreements contained in this Agreement, Utility agrees with Westmoreland as follows:

ARTICLE I
Definitions

When used in this Agreement, the terms defined in this Article I shall have the following meanings.


Section 1.1	Capital Costs

“Capital Costs” shall mean those costs incurred by SJCC for equipment replacement and major rebuilds of equipment, facilities and site improvements that are capitalized.

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Coal Supply Agreement


Section 1.2	CCR Disposal Agreement

“CCR Disposal Agreement” shall mean that certain Coal Combustion Residuals Disposal Agreement dated as of even date herewith between Westmoreland and Utility and any agreement amending or replacing such agreement.


Section 1.3	Coal Leases

“Coal Leases” shall refer to those certain coal leases (some whole coal leases and some portions of other coal leases) which are described in Exhibit A .


Section 1.4	Contract Year

“Contract Year” shall mean the period between January 1 ^st of a given calendar year and December 31 ^st of such calendar year, provided that (i) the 2016 Contract Year shall commence on the later of January 1, 2016 or the Effective Date and (ii) the 2022 Contract Year shall commence on January 1, 2022 and expire on June 30, 2022 (or on December 31, 2022 in the event that the Parties mutually agree to extend the Agreement pursuant to Section 2.5 ).


Section 1.5	Fruitland Coal Sublease

“Fruitland Coal Sublease” shall mean that particular Sublease dated August 18, 1980, between Western Coal Company as Sublessor and Utah International Inc. as Sublessee, which interest has been assigned to SJCC.


Section 1.6	Guaranty

“Guaranty” shall mean the Guaranty in the form of Attachment 1 and dated as of even date herewith, made by Westmoreland, (“ Guarantor”) and guaranteeing to Utility SJCC’s performance of its obligations hereunder, which Guaranty shall remain in place throughout the Term and, if applicable, the Extension Term.


Section 1.7	Mineable Coal

“Mineable Coal” shall mean (1) Preexisting Stockpile Coal and (2) Raw Coal that meets the following four criteria:


(A)	Is within the Coal Leases;


(B)	Can reasonably be expected to be mined utilizing the Mining Plans and Methods described in Exhibit C ; and


(C)	Can, when processed, reasonably be expected to meet the coal quality requirements described in Section 5.2(B) .

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Coal Supply Agreement


Section 1.8	Non-SJCC Coal

“Non-SJCC Coal” shall mean coal that is offered to Utility pursuant to Section 12.2 and meets the following criteria:


(A)	It has been approved by Utility for processing and delivery to the Delivery Point(s) or inclusion in the Reserve of Coal;


(B)	It can be processed to meet the coal size requirements described in Section 5.1 and the coal quality requirements in Section 5.2(B) ; and


(C)	It has been severed from sources other than the Coal Leases.


Section 1.9	Preexisting Stockpile Coal

“Preexisting Stockpile Coal” shall mean coal that as of the Effective Date is contained in the Reserve of Coal. SJCC represents and warrants that the amount of the Preexisting Stockpile Coal at the time of the Effective Date is equal to or greater than 4.8 million tons. The actual amount of Preexisting Stockpile Coal as of the Effective Date (“ Preexisting Stockpile Volume ”) shall be allocated across to the Contract Years during the Term in accordance with methodology set forth in Exhibit M (each such annual amount, “ Annual Preexisting Stockpile Amount ”). The Parties acknowledge and agree that the Annual Preexisting Stockpile Amount shall be zero (0) in certain Contract Years.


Section 1.10	Processed Coal

“Processed Coal” shall mean Mineable Coal and, as applicable, Non-SJCC Coal that has been processed according to Section 7.3 .


Section 1.11	Prudent Mining Practices

“Prudent Mining Practices” shall mean the practices, methods and acts engaged in or approved by a significant portion of the coal mining industry in the United States of America during the relevant time period and which practices, methods and acts would be expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition.


Section 1.12	Quarterly Price Adjustment

The Quarterly Price Adjustment shall mean a quarterly adjustment made to the Tier 1 Price, Tier 2 Price and Reduced Price each calendar quarter during each Contract Year in accordance with the formula and examples set out at Exhibit N , with the first such quarterly adjustment occurring as of the later of January 1, 2016 or the Effective Date.


Section 1.13	Raw Coal

“Raw Coal” shall mean all Mineable Coal other than Preexisting Stockpile Coal.

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Coal Supply Agreement


Section 1.14	Reclamation Services Agreement

“Reclamation Services Agreement” shall mean that certain Reclamation Services Agreement dated as of even date herewith by and between Westmoreland and Utility and any agreement amending or replacing such agreement.


Section 1.15	Reduced Price

The Reduced Price shall be $2.00 per ton as adjusted by the Quarterly Price Adjustment.


Section 1.16	Reserve of Coal

“Reserve of Coal” shall mean all Mineable Coal and Non-SJCC Coal on the SJCC Site Area that is mined coal in storage and, for the avoidance of doubt, includes that Raw Coal that is included in the surge pile at the exit of the underground mine on the SJCC Site Area (as shown on Exhibit E ).


Section 1.17	SJCC Environmental Force Majeure Price

“SJCC Environmental Force Majeure Price” shall mean $12.00 per ton.


Section 1.18	SJCC Site Area

“SJCC Site Area” is identified in Exhibit E and includes the following:


(A)	Coal Leases as described in Exhibit A .


(B)	San Juan Mine (as designated on Exhibit E ) and facilities including coal receiving, handling, delivery, and crushing facilities, coal weighing and sampling facilities, service road, maintenance and office buildings, fencing and auxiliary facilities.


(C)	La Plata Mine (as designated on Exhibit E ) and facilities including coal weighing facilities, service road, maintenance and office buildings, fencing and auxiliary facilities, all as owned by SJCC.


(D)	La Plata transportation corridor facilities (as designated on Exhibit E ) including the haul road, water system, fencing and auxiliary facilities.


Section 1.19	San Juan Station

That certain coal-fired power plant currently operated and owned, in part, by Utility and presently consisting of four generating units. The First Unit has a net rated capacity of approximately 340,000 kW. The Second Unit has a net rated capacity of approximately 340,000 kW. The Third Unit has a net rated capacity of approximately 496,000 kW. The Fourth Unit has a net rated capacity of approximately 507,000 kW. The Second Unit and the Third Unit will be retired no later than December 31, 2017.

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Coal Supply Agreement


Section 1.20	SPA

“SPA” means that Stock Purchase Agreement to be executed by Westmoreland and BHP Billiton New Mexico Coal Inc., pursuant to which Westmoreland shall agree to purchase the stock of SJCC and SJTC.


Section 1.21	Tier 1 Price

The Tier 1 Price shall be $35.30 per ton as adjusted by the Quarterly Price Adjustment.


Section 1.22	Tier 2 Price

The Tier 2 Price shall mean $17.00 per ton as adjusted by the Quarterly Price Adjustment.


Section 1.23	Tier 1 Tons

“Tier 1 Tons” shall mean:

(i)

With respect to the 2016 Contract Year and the 2017 Contract Year, 5.75 million tons; provided that if the “Closing” under the SPA occurs after December 31, 2015, the Tier 1 Tons for the 2016 Year shall be reduced by an amount equal to the Tier 1 Tonnage Allocation that would otherwise have been applicable to the period of time between January 1, 2016 and the Effective Date (prorated as necessary for any partial month);


(ii)	With respect to the 2018 Contract Year and the 2019 Contract Year, 2.8 million tons;


(iii)	with respect to the 2020 Contract Year and the 2021 Contract Year, 2.65 million tons; and


(iv)	With respect to the 2022 Contract Year, 1.4 million tons.


Section 1.24	Tier 2 Tons

“Tier 2 Tons” shall mean all tons delivered to and accepted by Utility at the Delivery Point(s) in a Contract Year in excess of Tier 1 Tons.


Section 1.25	Ton

Equal to two thousand (2,000) pounds and the same as a short ton when used herein.


Section 1.26	Ute ROW

“Ute ROW” shall mean that particular right of way agreement dated July 29, 1981, between Western Coal Company (which interest has been assigned to SJCC) and the Ute Mountain Ute Tribe of the Ute Mountain Ute Reservation, as amended.

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Section 1.27	Definitions of Other Terms

Terms appearing elsewhere throughout this Agreement, but not defined above, are defined in the body of this Agreement. These terms include:


(A)	“Acceptable Coal”, defined in Section 5.2(B) ;


(B)	“Affected Party”, defined in Section 12.1(A)(2);


(C)	“Agreement”, defined in Recitals ;


(D)	“Annual Operating Plan”, defined in Section 7.2(A) ;


(E)	“Annual Preexisting Stockpile Amount”, defined in Section 1.9 ;


(F)	“Annual Tonnage Schedule”, defined in Section 4.3(B) ;


(G)	“AOP Minimum Heat Content Requirement”, defined in Section 7.2(D) ;


(H)	“Applicable Period”, defined in Section 7.2(B)(1);


(I)	“Approved Annual Operating Plan”, defined in Section 7.2(D) ;


(J)	“Available Force Majeure Tons”, defined in Section 12.1(C)(3)(i) ;


(K)	“Available Preexisting Stockpile Tons”, defined in Section 12.1(C)(3)(i) ;


(L)	“CCR”, defined in Section 6.4 ;


(M)	“Cimarron Coal Assignment”, defined in Section 2.1(J) ;


(N)	“Coal Quality Measures”, defined in Exhibit H ;


(O)	“Cure Plan”, defined in Section 12.2(E)(1) ;


(P)	“Delivery Points”, defined in Section 4.2(B) ;


(Q)	“Effective Date”, defined in Section 2.3 ;


(R)	“Environmental and Safety Plan”, defined in Section 7.2(B)(1)(ii) ;


(S)	“Extension Notice”, defined in Section 2.5 ;


(T)	“Extension Term”, defined in Section 2.5 ;


(U)	“Force Majeure”, defined in Section 12.1 ;


(V)	“Force Majeure Tons”, defined in Section 12.1(C)(3)(iii)ii ;


(W)	“Force Majeure True-Up Amount”, defined in Section 8.7(C) ;

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(X)	“Heat Content Requirement”, defined in Section 5.2(B) ;


(Y)	“Installment Sale Agreement”, defined in Section 2.1(J) ;


(Z)	“Mine Plan”, defined in Section 7.2(B)(1)(i) ;


(AA)	“Monthly Preexisting Stockpile Amount”, defined in Section 8.1.(B);


(BB)	“Monthly Invoice”, defined in Section 8.7(A) ;


(CC)	“Monthly Tonnage Schedule”, defined in Section 4.3(B) ;


(DD)	“Monthly Report”, defined in Section 7.2(E) ;


(EE)	“Non-Conforming Coal”, defined in Section 5.2(C) ;


(FF)	“Party”, defined in Recitals ;


(GG)	“Preexisting Stockpile Volume”, defined in Section 1.9 ;


(HH)	“Required Reserve”, defined in Section 4.5(A);


(II)	“SJCC”, defined in Recitals;


(JJ)	“SJCC Default”, defined in Section 12.3 ;


(KK)	“SJCC Default Conditions”, defined in Section 12.3(A) ;


(LL)	“SJCC Environmental Force Majeure”, defined in Section 12.1(C) ;


(MM)	“SJCC Environmental Force Majeure Notice”, defined in Section 12.1(C)(1) ;


(NN)	“Term”, defined in Section 2.3 ;


(OO)	“Tier 1 Tonnage Allocation”, defined in Section 7.2(B)(1) ;


(PP)	“Trued-Up Annual Payment”, defined in Section 8.7(B) ;


(QQ)	“Unrecovered Capital Expenditures”, defined in Section 12.5(B) ;


(RR)	“Utility”, defined in Recitals ;


(SS)	“Utility Default”, defined in Section 12.4 ;


(TT)	“Utility Default Conditions”, defined in Section 12.4(A) ;


(UU)	“Utility Environmental Force Majeure”, defined in Section 12.1(B)(1) ;


(VV)	“Utility Payment Stream”, defined in Section 8.2 ; and

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(WW)	“Utility’s Coal Storage”, defined in Section 4.4 ;

ARTICLE II
Obligations of the Parties and Term of Agreement


Section 2.1	Obligations of SJCC

In addition to the obligations of SJCC otherwise set forth in this Agreement, SJCC agrees:


(A)	To economically and efficiently produce Raw Coal from the Coal Leases in a manner consistent with Prudent Mining Practices,


(B)	To process and crush Mineable Coal and/or Non-SJCC Coal in the facilities of SJCC to the size and quality specified in Section 5.1 and Section 5.2(B) , respectively,


(C)	To deliver and sell Processed Coal to Utility at the Delivery Point(s) and in sufficient quantity to meet one hundred percent (100%) of the fuel needs of the San Juan Station, including both projected burn and Utility’s Coal Storage and to maintain a sufficient Reserve of Coal in accordance with the terms of this Agreement,


(D)	To deliver the Reserve of Coal to Utility by the end of the Term; provided that, in the event this Agreement is extended pursuant to Section 2.5 , SJCC shall only be obligated to deliver Preexisting Stockpile Coal from the Reserve of Coal in a manner that ensures that the Preexisting Stockpile Coal is eliminated by the end of the Term,


(E)	To work collaboratively with Utility to identify and implement best practices for the production and delivery of coal and to perform the planning, budgeting and other services described in this Agreement in the most cost-effective and efficient manner possible,


(F)	To provide Utility with access to all records and documents of SJCC related to or generated in connection with the provision of services under the Agreement,


(G)	To comply with all applicable law and all governmental authorities having jurisdiction over any aspect of the services,


(H)	To coordinate all work provided under this Agreement with the “Service Provider” under the Reclamation Services Agreement so as to avoid any interference with the activities performed by Service Provider under the Reclamation Services Agreement,

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(I)	To coordinate all work provided under this Agreement with the “Service Provider” under the CCR Disposal Agreement so as to avoid any interference with the activities performed by Service Provider under the CCR Disposal Agreement, and

(J)

To perform all of the obligations contained in (i) the Cimarron Coal Assignment dated October 30, 1979, originally between Cimarron Coal Company and Western Coal Company and assigned to SJCC, as amended and modified, including but not limited to the letter amendment dated as of December 15, 2003 between AU Mines, Inc. and SJCC (“ Cimarron Coal Assignment ”) and (ii) the Installment Sale Agreement and Release between Cimarron Coal Company and SJCC, dated as of December 15, 2003 (“ Installment Sale Agreement ”).


Section 2.2	Obligations of Utility

In addition to the obligations of Utility otherwise set forth in this Agreement, Utility agrees:


(A)	To purchase one hundred percent (100%) of the coal required for the operation of the San Juan Station from SJCC in accordance with this Agreement, subject to Utility’s right, under Article XII to obtain alternate supply under Non-Normal Conditions; and


(B)	To make payments as specified in Article VIII .


Section 2.3	Term

This Agreement shall become effective simultaneous with the “Closing” under the SPA (such date on which the “Closing” occurs, the “ Effective Date ”) but subject to the effectiveness of the San Juan Restructuring Agreement. For purposes of this Section 2.3 , “San Juan Restructuring Agreement” means the San Juan Project Restructuring Agreement among and to be executed by the “Parties” thereto (as such term is defined therein). This Agreement shall expire on June 30, 2022 (the “ Term ”), unless terminated earlier as provided herein or extended by mutual written agreement of the Parties pursuant to Section 2.5 . As of the Effective Date, Westmoreland shall, by executing (and causing SJCC to execute) an Assignment and Assumption of Coal Supply Agreement in the form of Exhibit O , assign all of its right and obligations under this Agreement to SJCC and cause SJCC to assume all of Westmoreland’s rights and obligations under this Agreement. At the Effective Date, SJCC shall replace Westmoreland as a “Party” to this Agreement. Pursuant to Section 14.9 , Utility hereby consents to such assignment. Notwithstanding the foregoing, Westmoreland’s obligations as Guarantor hereunder shall not be assigned to SJCC. This Agreement shall automatically terminate in the event of a termination of the SPA.


Section 2.4	Guaranty

Guarantor has, as of the Effective Date, executed the Guaranty and provided the executed Guaranty to Utility and shall maintain the Guaranty for the duration of the Term and the Extension Term, as applicable. SJCC shall cause Guarantor to provide to Utility the

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audited financial statements of Guarantor on or before April 1 ^st of each Contract Year; provided Guarantor’s filing with the U.S. Securities and Exchange Commission of Guarantor’s 10-K containing the audited financial statements of Guarantor will be deemed to constitute delivery of such audited financial statements to the Utility.


Section 2.5	Extension

Utility shall have the right to seek to extend this Agreement beyond the Term (“ Extension Term ”) by giving written notice to SJCC on or before July 1, 2018 (“ Extension Notice ”). Upon Utility’s provision of an Extension Notice, the Parties shall promptly engage in good-faith negotiations concerning such Extension Term, including the pricing, volume and term. In the event that the Parties are unable to reach agreement with respect to the Extension Term prior to January 1, 2019, then the Agreement will expire at the end of the Term, unless terminated early as provided herein.


Section 2.6	Representations and Warranties

Each Party warrants and represents that as of the date hereof:


(A)	It is a corporation duly organized and in good standing in its state of incorporation and is qualified to do business and is in good standing in those states where necessary in order to carry out the purposes of this Agreement;

(B)

It has the capacity to enter into this Agreement and all transactions contemplated in this Agreement, and that all corporate actions required to authorize it to enter into this Agreement have been taken properly and will, and Westmoreland further warrants and represents that SJCC will, as of the Effective Date, have the capacity to perform this Agreement and all transactions contemplated in this Agreement, and that all corporate actions required to perform this Agreement shall have been taken properly; and


(C)	This Agreement has been duly executed and delivered by it and is valid and binding upon it in accordance with its terms.

ARTICLE III
Coal Supply


Section 3.1	Ownership of Coal

All coal contained in the Coal Leases is the property of SJCC (subject in the case of coal contained in the Fruitland Coal Sublease to certain security interests therein retained by other parties). Once said coal is delivered to the Delivery Point(s), title thereto shall pass to Utility and SJCC warrants that such title shall be free and clear of all claims, liens and encumbrances. SJCC shall defend Utility’s title with respect to all coal delivered to Utility under this Agreement and shall indemnify Utility against (i) all claims, demands, actions, suits, liabilities, and judgments asserted against Utility by any third party with respect to such title and (ii) all damages, costs, and expenses (including, without limitation, incidental damages, reasonable attorney’s fees, and litigation expenses) incurred by Utility

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in defending such title. Risk of loss shall remain with SJCC until the Processed Coal is deposited in one of the Utility’s coal surge piles at the Delivery Point(s).

ARTICLE IV
Delivery of Coal


Section 4.1	Delivery Obligation

SJCC will deliver Processed Coal to Utility at the Delivery Points(s) in sufficient quantity to meet one hundred percent (100%) of the fuel needs of the San Juan Station, including both projected burn and Utility’s Coal Storage requirements in accordance with this Agreement and the applicable Approved Annual Operating Plan.


Section 4.2	Delivery of Coal


(A)	SJCC will deliver Raw Coal to the Reserve of Coal. Raw Coal shall be deemed delivered when it is deposited in the Reserve of Coal. For the avoidance of doubt, risk of loss with respect to coal in the Reserve of Coal shall remain with SJCC.


(B)	SJCC will deliver Processed Coal to the delivery point(s) at the San Juan Station situated in the location(s) shown as “ Delivery Points ” on Exhibit B . Processed Coal shall be deemed delivered when it is deposited in one of Utility’s coal surge piles at the Delivery Point(s), at which point risk of loss shall pass to Utility.


(C)	Matters of mutual interest in connection with the coal handling facilities, and specific methods and locations of delivery shall be addressed by the Mining Oversight Committee, such responsibility to be carried out as provided for in Section 9.1 .


Section 4.3	Delivery Rates


(A)	SJCC shall deliver Processed Coal to Utility at the Delivery Point(s) pursuant to Section 4.3(B) , such deliveries to be in annual amounts as shown in Exhibit D as may be adjusted as provided for in Section 4.3(B) .

(B)

During the Term and Extension Term, as applicable, Utility will provide SJCC annually, on or before June 1 ^st , a schedule of monthly and annual planned coal consumption for operation of the San Juan Station and for Utility’s Coal Storage for the following Contract Year (each a “ Monthly Tonnage Schedule ” or “ Annual Tonnage Schedule ”, as the case may be). The Monthly Tonnage Schedule and Annual Tonnage Schedule will supersede the tonnage specified in Exhibit D for that Contract Year.


(C)	SJCC shall supply coal in accordance with the applicable Monthly Tonnage Schedule and Annual Tonnage Schedule and Utility shall be permitted to adjust the Monthly Tonnage Schedule and Annual Tonnage Schedule at any time upon notice to SJCC.

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Section 4.4	Utility’s Coal Storage

Utility intends to maintain at the San Juan Station site a storage pile of Processed Coal (“ Utility’s Coal Storage ”). The amount of such storage will be determined by Utility from time to time in the future and may be varied from time to time. Should any part of Utility’s Coal Storage be depleted or should the size of the pile be increased as provided for herein, SJCC agrees to deliver Processed Coal to the Delivery Point(s) in order that the amount of coal will reach the required level, as determined by Utility.


Section 4.5	Reserve of Coal


(A)	SJCC shall maintain a Reserve of Coal that is sufficient to meet the projected coal burn of San Juan Station for the subsequent six (6) to eight (8) months (“ Required Reserve ”), but not greater than twelve (12) months, as such projected coal burn is determined by Utility and included in the Annual Operating Plan.

(B)

SJCC shall deliver Mineable Coal from the Reserve of Coal in a manner that ensures that the Reserve of Coal is eliminated by the end of the Term; provided that, in the event this Agreement is extended pursuant to Section 2.5 , SJCC shall only be obligated to deliver Preexisting Stockpile Coal from the Reserve of Coal in a manner that ensures that the Preexisting Stockpile Coal is eliminated by the end of the Term.

ARTICLE V

Coal Specifications and Weighing, Sampling, and Analysis


Section 5.1	Coal Size

All coal delivered by SJCC pursuant to this Agreement shall be approximately 1.25 inches x 0 in size, subject to adjustment as determined by the Mining Oversight Committee.


Section 5.2	Coal Quality


(A)	Mining and Extraneous Materials . Coal to be delivered pursuant to this Agreement shall have been mined in accordance with Prudent Mining Practices and in a manner that minimizes contamination of coal by material extraneous to the coal seam being mined.

(B)

Acceptable Coal . SJCC shall deliver to Utility at the Delivery Point(s) Processed Coal that on a gross, as-received basis and averaged over a 24-hour period, has a heat content equal to (i) for the 2016 Contract Year, 9,000 Btu/lb, and (ii) for each subsequent Contract Year, the AOP Minimum Heat Content Requirement established in the Approved Annual Operating Plan for such Contract Year (such standard being the “ Heat Content Requirement ” and such coal meeting the Heat Content Requirement being “ Acceptable Coal ”). Such 24-hour period shall be from midnight to midnight.

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(C)	Non-Conforming Coal . If SJCC delivers Processed Coal to Utility at the Delivery Point(s) which on an as-received basis as averaged over any 24-hour period fails to meet the Heat Content Requirement (such coal being “ Non-Conforming Coal ”), then Utility, at its sole discretion, may elect to have SJCC remove such Non-Conforming Coal from Utility’s Coal Storage.


(D)	Coal Quality Measures . SJCC shall implement and maintain the Coal Quality Measures specified in Exhibit H and perform all such activities in a manner that maximizes the quality of the coal delivered at the Delivery Point(s) and minimizes coal quality variability.


Section 5.3	Weighing and Analysis Facilities and Methods

Facilities for the weighing, sampling and analysis of coal shall be owned, operated and maintained by SJCC. Methods shall be established for determining the weight and BTU content of coal delivered, in accordance with Prudent Mining Practices and applicable portions of the American Society for Testing and Materials standards, or such other procedures as the Mining Oversight Committee may determine with due regard for overall economy in investment and in operation, including splitting of samples and bias testing by an independent commercial firm qualified to conduct such testing.

ARTICLE VI
Coal Leases, Land, and Land Rights


Section 6.1	Dedicated Reserves

The coal contained within the Coal Leases is dedicated exclusively to production for the San Juan Station and shall not be sold to any third party.

Before SJCC acquires any coal leases contiguous with the Coal Leases, SJCC will offer to dedicate such coal leases to production for the San Juan Station under the terms of this Agreement. Upon approval (which approval shall not be withheld unreasonably) by the Joint Committee of the terms for incorporating such leases into this Agreement (including any necessary adjustments to Section 8.1 to account for any new taxes, royalties or other costs associated with such new leases), those coal leases if acquired, will become dedicated to production for the San Juan Station except as provided otherwise herein.

SJCC shall not mine coal from the coal leases described in the Cimarron Coal Assignment.


Section 6.2	SJCC’s Facilities


(A)	SJCC represents and warrants that as of the Effective Date, it has right of use of the SJCC Site Area, either by right, deed, lease, or other instrument.


(B)	It is understood that the boundaries of the SJCC Site Area that are adjacent to the San Juan Station may, with the consent of Utility, be enlarged as SJCC’s needs expand. Any such enlargement shall be a responsibility of the Joint Committee, to be carried out as provided for in Section 10.1 .

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(C)	Utility hereby agrees that as among Utility and SJCC and their respective successors and assigns, the coal mining, coal processing and related assets owned by SJCC and located on the San Juan Station site are and shall remain personal property of SJCC.


Section 6.3	Utility’s Rights Vis-a-Vis the SJCC Site Area

(A)

Utility shall have the right to enter the SJCC Site Area; provided that any representative of Utility entering the SJCC Site Area shall first give reasonable notice to the mine manager, or his representative, and comply with all safety requirements. SJCC shall provide assistance to any representative of Utility entering the SJCC Site Area, including, where requested by Utility, guided tours by employees of SJCC familiar with the operations of SJCC.

(B)

SJCC grants to Utility such rights as SJCC may have to install, maintain and operate and the right to permit others, including but not limited to affiliated companies of Utility, to install, maintain and operate roads, railroads, overland conveyors, electric power-lines, water pipelines and other facilities over and upon the SJCC Site Area; provided, however, that such installation, maintenance and operation shall not interfere with SJCC’s operations and obligations under this Agreement and provided further that such activity shall comply with applicable law and lease terms.


Section 6.4	CCR Disposal Area

In connection with the CCR Disposal Agreement, SJCC will maintain and make available, to the extent permitted by, and in compliance with, applicable laws, regulations and permits, suitable CCR disposal areas within the SJCC Site Area. “ CCR ” shall be defined as material disposed of pursuant to the CCR Disposal Agreement.


Section 6.5	Compliance with Leases and Other Instruments

(A)

SJCC shall not perform any act or undertake any activity which would violate any covenant under any of the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal and other activities of SJCC under this Agreement, and which could have the effect of causing forfeiture of SJCC’s rights under said leases and other instruments, including nonpayment of rentals or royalties due under the provisions of such leases and instruments.

(B)

It is agreed that, in the event there is attached to SJCC’s interest in the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal and other activities under this Agreement, a judgment lien against SJCC resulting from a final judgment issued by any court of competent jurisdiction, which judgment is not appealable to any court, or a lien created by statute, which statutory lien is not being contested by SJCC and which SJCC does not intend to contest, and legal procedure has been commenced for the sale of SJCC’s interest in

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the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal, and other activities of SJCC under this Agreement, pursuant to such judgment, lien or statutory lien, Utility, after giving SJCC written demand to pay such judgment or discharge such lien and SJCC having failed to do so within fifteen (15) days after such demand, shall have the right at its option to pay and discharge said judgment or lien prior to such sale or to redeem the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal and other activities of SJCC under this Agreement, after such sale as provided by law, in which event all sums expended by Utility to discharge said lien or to redeem said property, as provided by law, shall be payable by SJCC to Utility upon demand.


Section 6.6	Restrictions on SJCC


(A)	Notwithstanding Section 6.7 , SJCC shall not assign, transfer, convey, mortgage, encumber or otherwise dispose of interests or rights in the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal and other activities of SJCC under this Agreement, except:


(1)	as contemplated by Section 14.9 ; or


(2)	such encumbrances, mortgages or liens as may be required by SJCC’s (or an affiliate of SJCC’s) lenders in connection with the financing of SJCC’s business,

without the prior written consent of Utility, which consent will not be unreasonably withheld or restricted.


(B)	SJCC may not sell to parties other than Utility, coal mined from the Coal Leases and any approved contiguous lease additions.


Section 6.7	Site Area Lease Management

SJCC shall have the responsibility and authority to manage all leases, rights of way grants and easements, or other agreements, licenses or permits for the SJCC Site Area. Management of the Coal Leases and other areas required for the mining, processing, transportation, delivery, and supply of coal pursuant to this Agreement is restricted pursuant to Section 6.6 .


Section 6.8	Reclamation Services Agreement and CCR Disposal Agreement Coordination .

SJCC acknowledges and agrees that the “Service Provider” under the Reclamation Services Agreement and the “Service Provider” under the CCR Disposal Agreement will be performing obligations pursuant thereto within the SJCC Site Area and that the performance of such obligations will not in any way serve to excuse SJCC’s performance

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under this Agreement. SJCC agrees to grant access to the SJCC Site Area to the “Service Provider” under the Reclamation Services Agreement and the “Service Provider” under the CCR Disposal Agreement for purposes of performing such obligations.

ARTICLE VII
Operations


Section 7.1	Mining Plans and Methods


(A)	SJCC will mine and deliver coal in accordance with the Approved Annual Operating Plan, which will be developed in accordance with Section 7.2 and Exhibit C .


(B)	SJCC shall be responsible for arranging to obtain the electric power required for performing its obligations under this Agreement. Such electric power shall be obtained through Utility’s standard contract for electric service utilizing one of Utility’s approved tariff rates.


Section 7.2	Annual Operating Plan


(A)	SJCC shall, in consultation with the Mining Oversight Committee, prepare an “ Annual Operating Plan ” for each Contract Year; provided that the Approved Annual Operating Plan for the first Contract Year is attached as Exhibit G . SJCC shall conduct operations in accordance with the Approved Annual Operating Plan (as the same may be adjusted as provided herein).


(B)	Components of Annual Operating Plan .

(1)

The Annual Operating Plan shall provide detail by month for the upcoming Contract Year, by quarter for the following Contract Year, and annually for the remaining portion of the Term and Extension Term, as applicable (each, an “ Applicable Period ”). The Annual Operating Plan will include (i) the projected coal quality for all periods, (ii) the projected quantities of coal to be delivered during all periods, (iii) the schedule of deliveries of coal, (iv) the source or sources of coal to be delivered to Utility during all periods, (v) proposed changes in coal inventories including the Reserve of Coal and Utility’s Coal Storage levels and all other information specified in Exhibit C or as required by Utility, and (vi) a schedule ratably allocating an amount equal to the Tier 1 Tons minus the Annual Preexisting Stockpile Amount on a monthly basis based on the Utility’s monthly planned coal consumption provided by Utility in accordance with Section 4.3(B) for the Contract Year (such allocation, the “ Tier 1 Tonnage Allocation ”). The Annual Operating Plan shall consist of the following components:


(i)	A “ Mine Plan ” component setting forth mining sequences by Applicable Period under the proposed Annual Operating Plan. The sequence information shall include, but shall not be limited to, information related to development and longwall advance and

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tonnages, equipment utilization, coal quality and current geological and coal quality models.


(ii)	An “ Environmental and Safety Plan ” component which shall include environmental and safety goals and improvement focus areas.


(2)	Although not part of the Annual Operating Plan, SJCC shall, for informational purposes only, provide to Utility on an annual basis all planned Capital Costs for the upcoming Contract Year.


(C)	Review and Approval of Annual Operating Plan .


(1)	On or before June 1 ^st of each Contract Year, Utility shall provide SJCC with the following information that will assist SJCC with the preparation of the Annual Operating Plan for the following Contract Year:


(i)	non-binding, good faith estimates of tonnage demand by month for the upcoming Contract Year and annually for the remaining portion of the Term and Extension Term, as applicable;


(ii)	the timing of any planned outages at San Juan Station during the upcoming Contract Year;


(iii)	such other information as Utility may deem relevant or that is reasonably requested by SJCC in connection with the preparation of the Annual Operating Plan for the upcoming Contract Year and the remaining portion of the Term and Extension Term, as applicable.

(2)

On or before July 1 ^st of each Contract Year of the Term and Extension Term, as applicable, SJCC shall submit a preliminary Annual Operating Plan for the next Contract Year to the Mining Oversight Committee. SJCC shall present and discuss the preliminary Annual Operating Plan at a meeting of the Mining Oversight Committee called for that purpose no later than July 15 ^th of such Contract Year and the Mining Oversight Committee shall promptly provide comments to SJCC. SJCC shall consider the comments of the Mining Oversight Committee and submit the proposed Annual Operating Plan to the Mining Oversight Committee by August 1 ^st of such Contract Year. The Mining Oversight Committee shall provide SJCC with notice of any specific exceptions to the Annual Operating Plan no later than September 1 ^st of such Contract Year. Any such issues not resolved by October 1 ^st of such Contract Year by approval of an Annual Operating Plan by the Mining Oversight Committee shall promptly be presented to the Joint Committee for resolution by October 15 ^th .


(D)	Decisions on Annual Operating Plan .

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The Annual Operating Plan approved by the Mining Oversight Committee will be sent to the Joint Committee for final approval, unless any issues are not resolved by the Mining Oversight Committee, in which case all unresolved issues will be provided to the Joint Committee in accordance with Section 7.2(C)(2) . The Annual Operating Plan approved by the Joint Committee shall be deemed the “ Approved Annual Operating Plan ” and the minimum heat content requirement specified therein shall constitute the “ AOP Minimum Heat Content Requirement ”. In the event that the Parties cannot agree on an Approved Annual Operating Plan for a Contract Year, the last Approved Annual Operating Plan shall remain in effect and the applicable year of such Approved Annual Operating Plan shall be utilized for the upcoming Contract Year; provided, however, that in the event that the Parties are unable to agree to a AOP Minimum Heat Content Requirement, the Parties shall allow such AOP Minimum Heat Content Requirement to be set by a qualified independent mining geology firm, the costs and expenses of which shall be shared equally by the Parties.


(E)	Reporting on Approved Annual Operating Plan .

SJCC shall provide a report on monthly basis to the Mining Oversight Committee containing, at a minimum, the following (“ Monthly Report ”): (i) the schedule of deliveries of Raw Coal to the Reserve of Coal; (ii) the schedule of deliveries of Raw Coal and Preexisting Stockpile Coal from the Reserve of Coal (each processed in accordance with the Agreement) to the Delivery Point(s); (iii) any changes in the actual and projected coal quality for all periods; (iv) the source or sources of coal to be delivered to Utility during all periods; and (v) any proposed changes in the Reserve of Coal.


(F)	Emergency .

Notwithstanding any other provision of this Agreement, if an emergency threatens life, limb or property or the safety, integrity or operability of the mine or requires immediate action in order to comply with laws, orders, rules or regulations, SJCC may take such action whether or not consistent with the Approved Annual Operating Plan as in its sole discretion, reasonably exercised, it may deem prudent or necessary to end the emergency or otherwise mitigate its effects. SJCC shall notify Utility promptly of any such action with all relevant details associated therewith and with the costs incurred as a result of the emergency. The Approved Annual Operating Plan shall automatically be revised to include all costs for which SJCC is entitled to reimbursement pursuant to this Section 7.2(F) .


Section 7.3	Processing Methods


(A)	SJCC shall process Mineable Coal and/or Non-SJCC Coal in its facilities in accordance with accepted coal processing methods to meet size and quality specifications in Section 5.1 and Section 5.2 , respectively.

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Section 7.4	Reclamation Activities .

SJCC acknowledges that it is required by applicable laws and regulations (including any newly adopted laws and regulations that may be applicable), leases and surface agreements, and conditions of applicable permits, licenses and approvals to reclaim lands on the entire SJCC Site Area, including contemporaneous and final, closure reclamation for past and current mining and related activities under this Agreement and its predecessor agreements. Utility will compensate SJCC for all such reclamation liabilities associated with disturbance of the SJCC Site Area resulting in any way from the supply of coal to the San Juan Station, except for any reclamation liabilities arising from SJCC’s material breach of the Reclamation Services Agreement by SJCC (in its role as Service Provider under such agreement), including any violation by SJCC of Applicable Law (as that term is defined in the Reclamation Services Agreement). Utility will be responsible for contracting for the provision of all such reclamation activities (which compensation obligation is being satisfied by Utility pursuant to the Reclamation Services Agreement). As of the Effective Date, Utility has made arrangements pursuant to the Mine Reclamation and Trust Funds Agreement effective as of the “Closing” under the SPA, which arrangements have been approved by Westmoreland, to, among other things, assure Utility’s post-Term reclamation obligations under this Section 7.4 .

ARTICLE VIII
SJCC Compensation


Section 8.1	Compensation Components

SJCC’s compensation shall be comprised of the following items:


(A)	Utility shall pay to SJCC on a monthly basis an amount equal to the monthly Tier 1 Tonnage Allocation included in the Approved Annual Operation Plan multiplied by the applicable Tier 1 Price; provided that, for the avoidance doubt, such amount shall be paid in each month regardless of whether any tons are actually delivered to the Delivery Point(s).

(B)

Utility shall pay to SJCC on a monthly basis an amount equal to one-twelfth (1/12) of the Annual Preexisting Stockpile Amount (“ Monthly Preexisting Stockpile Amount ”) (which the Parties acknowledge and agree shall be zero (0) in certain Contract Years) multiplied by the applicable Reduced Price; provided that, for the avoidance doubt, such amount shall be paid in each month regardless of whether any tons are actually delivered to the Delivery Point(s).


(C)	In consideration for each ton of coal processed in accordance with Section 7.3 and delivered to the Delivery Point(s) and constituting Acceptable Coal and in excess of the sum of the monthly Tier 1 Tonnage Allocation plus Monthly Preexisting Stockpile Amount, Utility shall pay to SJCC the applicable Tier 2 Price.

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(D)

Reimbursement of the actual and substantiated taxes and royalties identified in Exhibit I that are reasonably incurred in connection with the work performed under this Agreement with no markup or overhead; provided that SJCC shall exert commercially reasonable efforts in accordance with Prudent Mining Practices to minimize the total amount of such taxes and royalties paid in connection with SJCC’s work performed under this Agreement.


(E)	Reimbursement of the Utility Payment Stream in accordance with Section 8.2 .


(F)	Reimbursement of the REI (as defined in the Fruitland Coal Sublease).


(G)	Reimbursement of the Substitute REI in accordance with Section 8.3 .


(H)	Reimbursement of the Ute ROW in accordance with Section 8.4 .


Section 8.2	Payment of the Utility Payment Stream

For purposes of this Section 8.2 , the following definitions apply:

“Yl” is the final Implicit Price Deflator Index of the Gross Domestic Product (“IPD-GDP”) (defined below) for the fourth quarter of 2002, presently equal to 85.651.

“Y2” is the final IPD-GDP for the fourth quarter of 1979, presently equal to 41.986.

“Xl” is the most recently published quarterly IPD-GDP as of the Calculation Date. The Calculation Date is the 5 ^th day of the month following the month for which each Utility Payment Stream payment is being made (e.g., February 5 for the January payment).

The factors X1/Y1 and X1/Y2 as applied below in this Section 8.2 are utilized to recognize the effects of inflation and deflation on certain relevant base amounts.

The IPD-GDP as utilized in this Section 8.2 refers to the Implicit Price Deflator of the Gross Domestic Product Index (“Index”), a quarterly index that is published online by the Bureau of Economic Analysis of the U.S. Department of Commerce (“BEA”). At present, the Index is calculated and based on the reference year of 2009 = 100. The index is updated monthly and can be found in National Income and Products Accounts (“NIPA”) Table 1.1.9, Implicit Price Deflators for Gross Domestic Product, at:

http://www.bea.gov/iTable/iTable.cfm?ReqID=9&step=1#reqid=9&step=3&isuri=1&9

03=13.

Calculations for this Section 8.2 shall be made based upon the most recent Index information published on the BEA website. If the BEA website no longer publishes the Index, then the Index as most recently published in the Survey of Current Business shall be utilized, at the applicable Calculation Date. The Survey of Current Business is an online publication provided by the BEA and is available at: http://www.bea.gov/scb/index.htm .

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The Parties agree that any update to the Index after the Calculation Date, caused by BEA adjusting its estimates, shall not result in a recalculation of the amount of a Utility Payment Stream payment.

If, in the future, the BEA should change the reference year utilized to calculate the IPD-GDP then: Yl shall be the IPD-GDP shown for the fourth quarter of 2002; and Y2 shall be the IPD-GDP shown for the fourth quarter of 1979, in conversion tables prepared by the BEA with respect to the new reference year and Xl for each succeeding Utility Payment Stream payment becoming due after the date of the change of reference years shall be determined by reference to the most recently published IPD-GDP, as of the Calculation Date, based on the new reference year.

If the IPD-GDP should cease to be published by the BEA but another comparable index is published by another governmental agency then such index shall be utilized in the same manner as provided in this Section 8.2 in order to establish the amounts of the Utility Payment Stream becoming due for required future Utility Payment Stream payments. If no such index is published by governmental agencies, then such other index which may be available shall be utilized in a manner which will fairly and reasonably reflect the effects of inflation or deflation on the dollar amounts of the Utility Payment Stream payments.

Utility shall pay to SJCC the Utility Payment Stream calculated as follows (“ Utility Payment Stream ”):

1) Monthly payments (“Payment(s)”) each in the amount calculated in this Section 8.2(l) below. The first Payment is due for the month in which this Agreement becomes effective and the final Payment is due for the month of December 2017. The term Payment(s) as defined in this Section 8.2(l) apply only in this Section 8.2(1) .

The amount of each Payment shall be calculated utilizing $445,050.00 as the base amount to be subject to inflation and deflation adjustment that is calculated, mathematically, by the following formula, applied separately, for each Payment:

$445,050.00 x (X1/Y1) = amount of Payment

Utility shall make the Payments specified in this Section 8.2(1) to an SJCC bank account designated as Wells Fargo Bank N.A. escrow account 15539700 (or such other account as either of the Parties may designate upon 30 days written notice to the other party). Each Payment is due on the 22 ^nd day of the month following the month for which the Payment is being made. Payments due on a Saturday will be payable on the previous Friday. Payments due on a Sunday will be payable on the following Monday. Payments due on a bank holiday will be payable on the next bank workday.

2) Monthly payments (“Payment(s)”) each in the amount calculated in this Section 8.2(2) below. The first Payment is due for the month in which this Agreement becomes effective and the final Payment is due for the month of December 2017. The term

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Payment(s) as defined in this Section 8.2(2) applies only in this Section 8.2(2) . The amount of each Payment shall be calculated by adding certain payment amounts as follows:

Tier 1 shall be calculated utilizing $96,875 as the base amount to be subject to inflation and deflation adjustment and calculated mathematically by the following formula applied separately for each Payment:

$96,875 x (X1/Y2) = Tier 1 payment

If the LPM Annual Production (the total tons mined and delivered to Utility in a calendar year from the La Plata Mine) is zero, no payments are due for Tier 2 and Tier 3. Only if the LPM Annual Production exceeds 1,250,000 tons in any year after 2003, payments from at least Tier 2, and possibly Tier 3, shall be added to the December Tier 1 payment, as described below. Tier 2 and Tier 3 payments are only calculated and applied to the December payment of each year and shall be calculated utilizing $3.00/ton as the base amount to be subject to inflation and deflation adjustment.

Tier 2 only applies when LPM Annual Production exceeds 1,250,000 tons in any year after 2003. If LPM Annual Production exceeds 1,250,000 tons, the Tier 2 payment amount calculation is initiated by multiplying 50% by the lesser of: i) the LPM Annual Production minus 1,250,000 tons or ii) 250,000 tons, and then multiplying the product by $3.00/ton, multiplied further by X1/Y2, This product multiplied by 31% is the Tier 2 payment amount, and it shall be added to the Tier 1 payment amount for December each year that Tier 2 applies.

Tier 3 only applies when LPM Annual Production exceeds 1,500,000 tons in any year after 2003. If LPM Annual Production exceeds 1,500,000 tons, the Tier 3 payment amount calculation is initiated by multiplying 10% by: (the LPM Annual Production minus 1,500,000 tons), and then multiplying the product by $3.00/ton, multiplied further by Xl/Y2. This product multiplied by 31% is the Tier 3 payment amount, and it shall be added to the sum of the Tier 1 and Tier 2 payment amounts for December each year that Tier 3 applies.

Utility shall make the Payments specified in this Section 8.2(2) to the SJCC bank account designated as Wells Fargo Bank, N.A. escrow account 15339800 (or such other account as either of the Parties may designate upon 30 days written notice to the other party). Each Payment is due on the 22nd day of the month following the month for which the Payment is being made. Payments due on a Saturday will be payable on the previous Friday. Payments due on a Sunday will be payable on the following Monday. Payments due on a bank holiday will be payable on the next bank workday.

By the tenth (10th) day of each month, SJCC shall provide to Utility a detailed calculation of the Utility Payment Stream due for the previous month. In the event of a dispute between the Parties or with a third party over calculation of payments set out in Section 8.2(1) or Section 8.2(2) , Utility shall submit their written position statement

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regarding the disputed calculation to SJCC. A determination of the same issue in a dispute resolution process involving a third party, in which Utility’s position statement is presented in good faith by SJCC, shall be binding upon SJCC and Utility for purposes of this Agreement.


Section 8.3	Substitute REI

Utility shall pay to SJCC an amount that is annually equal to the REI (as defined in the Fruitland Coal Sublease) multiplied by "X" (which may be negative). The monthly invoiced amounts will be based on the projected number of Fruitland Substitute Tons (defined below) and Fruitland Tons (defined below) for the calendar year.

Where:

X=A-G

And

A=The number of Fruitland Substitute Tons is defined as all Tons except Fruitland Tons delivered to SJGS by SJCC, excluding the first 1,500,000 Tons other than those subject to the Fruitland Coal Sublease, provided, however, that the number of Fruitland Substitute Tons in any year will not exceed the greater of (i) the REI Minimum (as defined below) plus the REI Shortfall Balance as of the previous year end (as defined below) less the Fruitland Tons, or (ii) zero (0).

B=The aggregate cumulative number of Make-up Tons (as defined in the Fruitland Coal Sublease) as of the previous year end.

C=The REI Shortfall Balance as of the previous year end. The REI Shortfall Balance for 2015 year end is zero (0). The ending REI Shortfall Balance for each year thereafter will be the greater of (i) the sum of the ending REI Shortfall Balance for the previous year and the REI Shortfall Tons (as defined below) for the year, or (ii) zero (0).

D=The number of Fruitland Tons is defined as the actual number of Tons mined and delivered from the Fruitland Leases (as defined in the Fruitland Coal Sublease) during the year.

E=The REI Minimum, that shall be equal to the Annual Tonnage defined in the Fruitland Coal Sublease.

F=(D-E-C), or zero (0), whichever is greater and

G=(B-C), or F, whichever is less.

REI Shortfall Tons means for any year the REI Minimum for that year less the sum of Fruitland Tons and Fruitland Substitute Tons for that year. (REI Shortfall Tons may be negative).

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Section 8.4	Payments under the Ute ROW

Each month, Utility shall pay to SJCC all of SJCC’s actual and substantiated costs, if any, arising from the Ute ROW.


Section 8.5	Gas Wells

Each month, Utility shall pay to SJCC all of SJCC’s actual and substantiated costs reasonably incurred (without any mark-up) arising from any settlement or buyout costs associated with gas wells on the Coal Leases. SJCC shall exert commercially reasonable efforts to limit the amount of any such costs. For the avoidance doubt, Utility shall not be obligated to reimburse SJCC for costs related to the capping, plugging or abandonment of such gas wells.


Section 8.6	Reclamation Bond Premium

Each month, Utility shall pay to SJCC the same amount paid to Service Provider under the Reclamation Services Agreement and CCR Disposal Agreement in respect to Service Provider’s reclamation bond premium (the Parties acknowledging that one-third (1/3) of the total reclamation bond premium is being allocated equally between this Agreement, the Reclamation Services Agreement and the CCR Disposal Agreement).


Section 8.7	Invoicing, Monthly Reports and Settlement


(A)	Invoicing and Payment

The accounting and billing period under this Agreement shall be one month. Such one-month period shall be a fiscal month (currently defined as a calendar month) as adopted by SJCC unless the Joint Committee shall specify a different one-month period. Both Utility and SJCC recognize that some of the information applicable to an invoice may not be available at the time the invoice is prepared by SJCC and submitted to Utility. In such event, the submitted invoice shall be based upon the best available information. Upon receipt of such formerly unavailable information, SJCC shall prepare and furnish to Utility a supplemental invoice.

On a monthly basis, SJCC shall prepare and provide Utility with a Monthly Report and an invoice (“ Monthly Invoice ”) in a form to be agreed upon by the Parties. All payments owed by Utility to SJCC shall be based on the Monthly Invoice, which Monthly Invoice shall itemize (i) all Raw Coal delivered to the Reserve of Coal; (ii) that amount owed in connection with the monthly Tier 1 Tonnage Allocation and the Annual Preexisting Stockpile Amount pursuant to Section 8.1(A) and (B) ;(iii) that amounts owed by Utility to SJCC pursuant to Section 8.1(C) ; (iv) all Processed Coal delivered to the Delivery Point(s) and (v) all amounts owed by Utility to SJCC in respect of Section 8.1(D) , Sections 8.2 through 8.6 above along with an itemized summary of such costs. SJCC shall submit an invoice for a month no later than the tenth (10 ^th ) business day of the subsequent month. Payment shall be made by Utility by the later of (i) the twenty-second (22 ^nd ) day of the month succeeding the month for which such invoice is submitted or (ii) on the twelfth (12 ^th ) day after

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receipt of the invoice by Utility. Payment pursuant to this Agreement shall be made to SJCC by electronic funds transfer to such bank accounts as SJCC may from time to time designate.


(B)	Annual True-Up

At the end of each Contract Year, SJCC shall determine the “Trued-Up Annual Payment.” The “ Trued-Up Annual Payment ” shall be, for each Contract Year, the sum of (i) the tons of Processed Coal delivered at the Delivery Point(s) up to the Tier 1 Tons minus the Annual Preexisting Stockpile Amount multiplied by the applicable Tier 1 Price plus (ii) the Annual Preexisting Stockpile Amount multiplied by the applicable Reduced Price plus (iii) all additional tons of Processed Coal delivered at the Delivery Point(s) multiplied by the applicable Tier 2 Price. In the event that the total of Utility’s monthly payments pursuant to Sections 8.1(A) , (B) , and (C) in such Contract Year is greater than the Trued-Up Annual Payment, SJCC shall refund such excess payment to Utility no later than January 31 ^st of the Contract Year following the year for which such refund is due.


(C)	True-Up Due to Force Majeure Suspension

At the end of any Contract Year in which SJCC is prevented from delivering or Utility is prevented from accepting Processed Coal at the Delivery Point(s) due to Force Majeure in accordance with Section 12.1(A) , SJCC shall determine the “Force Majeure True-Up Amount.” The “ Force Majeure True-Up Amount ” shall be, for each Contract Year, the sum of (i) the tons of Processed Coal delivered at the Delivery Point(s) up to the Tier 1 Tons minus the Annual Preexisting Stockpile Amount multiplied by the applicable Tier 1 Price plus (ii) the Annual Preexisting Stockpile Amount multiplied by the applicable Reduced Price plus (iii) all additional tons of Processed Coal delivered at the Delivery Point(s) multiplied by the applicable Tier 2 Price. In the event that the total of Utility’s monthly payments pursuant to Sections 8.1(A) , (B) , and (C) in such Contract Year is less than the Force Majeure True-Up Amount, SJCC shall invoice Utility such payment in January of the Contract Year following the year for which such refund is due.


(D)	Accounting Records

SJCC shall maintain its accounts and records in accordance with United States Generally Accepted Accounting Principles. SJCC shall retain such accounts and records for any Contract Year for five (5) years following the end of such Contract Year, and for such reasonable additional period as specifically requested by Utility.


(E)	Disputed Invoices

In case any portion of an invoice shall be in dispute, the undisputed amount shall be paid when due; provided however, that Utility may also pay the disputed portion of such invoice without thereby waiving its right to contest such disputed portion.

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(F)	Failure to Pay

In the event Utility fails to pay any amount due and not in bona fide dispute, Utility shall pay SJCC interest on all amounts owing under any invoice submitted hereunder which are not paid when due and payable, with said interest to be calculated at the Prime Rate as published in the Wall Street Journal for corporate loans posted by at least seventy-five percent (75%) of the nation’s largest banks (or its equivalent) plus three percent (3%) but not in excess of the maximum rate of interest permitted by law and to be paid for the actual number of days elapsed from and including the date the invoice was due and payable until funds are received in SJCC’s account. This right shall not be deemed an exclusive right or remedy.


(G)	Suspension of Payment for Failure to Deliver

In the event SJCC fails to deliver Processed Coal at the Delivery Point(s), which failure to deliver is not caused by Utility, and which failure to deliver is not excused by the provisions of Section 12.1 hereof, and if such failure to deliver continues for ten (10) days after final demand for delivery by Utility, Utility shall have the right to suspend payment for any coal previously delivered by SJCC until coal deliveries shall have re-commenced. This right shall not be deemed an exclusive right or remedy.


(H)	Record-Keeping and Audits

SJCC will keep books, records and accounts necessary to support all amounts invoiced under this Agreement. Upon Utility’s request, SJCC shall supply Utility, by report and/or with actual source documents (as determined by Utility), the information reasonably necessary, at the sole reasonable discretion of Utility, to verify any invoice rendered to Utility pursuant to this Agreement.

From time to time but not more often than once in any Contract Year, Utility shall have the right to have an audit performed of SJCC’s books and records to verify that those books and records are maintained in accordance with United States Generally Accepted Accounting Principles and that invoices for the year or years being audited have been correctly calculated and only include amounts due and owing under this Agreement. No invoice, even if paid, shall be deemed final pending the results of the audit. If the audit finds that a paid invoice has not been correctly calculated or includes amounts that are not due and owing under this Agreement, SJCC shall promptly refund the amount of the charge determined to be improper with interest calculated from the date that Utility paid the invoice. To the extent that the audit concludes that an unpaid invoice has not been correctly calculated and includes amounts that are not due and owing under this Agreement, Utility shall not be required to pay that amount. Any audit must be commenced within two (2) years after the year being audited and if more than two (2) years have passed from the year, all invoices from such year shall be deemed to be correct and will not thereafter be subject to verification.

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Any dispute between Utility and SJCC, whether following an audit or not, as to whether SJCC’s books and records are maintained in accordance with United States Generally Accepted Accounting Principles or that an invoice has not been correctly calculated or includes amounts not due and owing under this Agreement, shall be referred to the Joint Committee for resolution.

ARTICLE IX

Mining Oversight Committee


Section 9.1	Purpose

The intent of the Parties in providing for a Mining Oversight Committee is to establish an orderly and continuing means of dealing with certain engineering and operating problems which may arise from time to time in carrying out the provisions of this Agreement. The Mining Oversight Committee shall have two (2) members and shall be responsible for making decisions concerning said engineering and operating problems which may arise from time to time under this Agreement, including those matters expressly specified herein.


Section 9.2	Mining Oversight Committee Members

The Mining Oversight Committee shall be comprised of SJCC’s mine manager and Utility’s fuel manager. Each such representative shall be authorized by the party by whom he is designated to act on its behalf with respect to matters herein specified to be the responsibilities of the Mining Oversight Committee, but shall have no authority to amend this Agreement. A representative may not delegate his responsibilities to others, but Utility, or SJCC, may designate an alternate to act when the representative is unavailable.


Section 9.3	Procedures and Practices

The Mining Oversight Committee shall meet, at a minimum, on a monthly basis. It shall be the responsibility of the Mining Oversight Committee to establish or approve, for the guidance of the local operating personnel of the respective Parties, procedures and standard practices, consistent with the provisions of this Agreement, with respect to:


(A)	Production and delivery of the coal.


(B)	Review and approval and recommendation to the Joint Committee of the Annual Operating Plan in accordance with Section 7.2 .


(C)	Changes in the 24-hour period used in measuring the quality of coal delivered pursuant to Section 5.2(B) or Section 5.2(C) .


(D)	Operations involved in the delivery of coal per Section 4.2 and in the weighing, sampling and analysis of coal pursuant to Section 5.3 .

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(E)	Operating, accounting and reporting details required to carry out the provisions of this Agreement with respect to invoicing and settlement pursuant to Section 8.7 .


(F)	Exchange of technical information and data pertinent to coal mining, reclamation and delivery operations under this Agreement.


(G)	Any other matters expressly made the responsibility of the Mining Oversight Committee under the terms of this Agreement.


Section 9.4	Mining Oversight Committee Decisions

The establishment or approval of a procedure or standard practice shall be evidenced by the signatures of both representatives of the Mining Oversight Committee.


Section 9.5	Relationship to Joint Committee and Arbitration

If the Mining Oversight Committee fails to resolve matters referred to it pursuant to this Agreement, such matters shall be submitted to the Joint Committee for resolution as provided for in Section 10.1 .

ARTICLE X
Joint Committee


Section 10.1	Purpose

The intent of the Parties in providing for a Joint Committee is to establish an orderly and continuing means of dealing with major matters which may arise from time to time in carrying out the provisions of this Agreement and for the resolution of matters which cannot be resolved by the Mining Oversight Committee, as more specifically defined below. The Joint Committee shall have two (2) members.


Section 10.2	Designation

During the Term and Extension Term, as applicable, SJCC will, by notice to Utility, designate one (1) individual as its representative on the Joint Committee, and Utility will, by notice to SJCC, designate one (1) individual as its representatives on the Joint Committee; and each such representative shall be authorized by the party(ies) by whom he is designated to act on its behalf with respect to matters herein specified to be responsibilities of the Joint Committee. A representative may not delegate his responsibilities to others, but Utility, or SJCC, may designate an alternate to act when said representative is unavailable. Either Utility, or SJCC, by notice to the other, may change the designation of its representatives.


Section 10.3	Authority

The Joint Committee shall have the following authority, and shall have the responsibility to act if appropriate, with respect to the following matters:

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(A)	Review and approval of the Annual Operating Plan in accordance with Section 7.2 .


(B)	Establish policies, programs and procedures for determination of the level of coal to be purchased and paid for by Utility, if any, during periods when operation of the San Juan Station is materially curtailed or prevented by Force Majeure.


(C)	Consider and attempt to resolve any disputes arising between the Parties related to the subject matter of this Agreement that may be referred to the Joint Committee.


(D)	Consider the enlargement of the space made available to SJCC at the San Juan Station site pursuant to Section 6.2(B) .


(E)	Consider any other matters expressly made the responsibility of the Joint Committee under the terms of this Agreement.


Section 10.4	Decisions by the Joint Committee

Decisions by the Joint Committee shall require the unanimous approval of all representatives of the Joint Committee and shall be evidenced by the signatures of all said representatives.


Section 10.5	Relationship to Arbitration

If the Joint Committee fails to resolve matters referred to it pursuant to this Agreement, such matters may be submitted to and determined by arbitration as provided for in Section 11.1 .

ARTICLE XI
Dispute Resolution


Section 11.1	Matters To Be Arbitrated; Notice of Claims and Defenses; Party Arbitrator Designation

Either Party may demand final and binding arbitration of any dispute, claim or controversy arising out of or relating to this Agreement, performance or actions pursuant to this Agreement, or concerning the interpretation of this Agreement (whether such matters sound in contract, tort or otherwise and including without limitation repudiation, illegality, and/or fraud in the inducement) by giving written notice to the other Party of all claims it desires to submit to arbitration; provided, however, that matters within the authority of the Joint Committee must be presented first to that committee for consideration. The notice shall include: (a) the demanding Party’s designation of a Party arbitrator; and (b) a detailed statement of the facts and theories supporting the claims. The Party on whom the arbitration demand is served shall have thirty (30) days from receipt of the notice to respond in writing to the demand and to submit any additional claims it wishes to submit to arbitration at the same time. The response also shall include: (a) the designation of the Party arbitrator for that Party; and (b) a detailed statement of the facts and theories supporting the claims and/or defenses asserted. The Party originally

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demanding arbitration shall reply in writing to any additional claims submitted within ten (10) days from the receipt of such response.


Section 11.2	Arbitrators; Selection of Neutral Arbitrator

Any Party who fails to designate timely its Party arbitrator shall forfeit its right to designate an arbitrator. If only one arbitrator is timely designated, that single arbitrator shall hear the dispute. If two arbitrators are timely designated, those arbitrators shall, within thirty (30) days, either agree on the appointment of a third, disinterested arbitrator knowledgeable as to the subject matter involved in the arbitration or petition the Chief Judge of the United States District Court for the District of New Mexico for the appointment of a third arbitrator. The Parties shall be equally liable for the reasonable fees and expenses of the neutral arbitrator hearing the dispute. The Parties shall be responsible for the fees and expenses of their respective Party-appointed arbitrator.


Section 11.3	Arbitration Hearings, Procedures and Timing

All reasonable efforts will be made to hold a hearing on the claims submitted within sixty (60) days after the appointment of the last arbitrator. In conducting the hearing, the arbitrators are directed, where feasible and where not inconsistent with the provisions of this section, to adhere to the then-existing American Arbitration Association procedures and rules relating to commercial disputes. Unless otherwise agreed by the Parties, the hearing shall be held in Albuquerque, New Mexico.


Section 11.4	Choice of Law

The arbitrators shall apply the laws of the State of New Mexico.


Section 11.5	Award and Enforcement

The decision or award of the arbitrators shall be given in writing within thirty (30) days after the conclusion of the hearing. The arbitrators are authorized to award money damages, injunctive and declaratory relief and/or specific performance, if such relief in their opinion is appropriate. In any arbitration, each Party shall bear its own costs, expenses, and attorneys’ fees. The arbitrators do not have authority to award costs, expenses, or attorneys’ fees to the prevailing Party. The award or decision of the arbitrators shall be subject to review or enforcement in accordance with the New Mexico Uniform Arbitration Act, NMSA 1978 §§ 44-7-1 et seq. Any Party shall be entitled to recover reasonable attorneys’ fees and costs incurred in enforcing any arbitration award or decision made pursuant to the arbitration provisions of this Agreement.


Section 11.6	Performance Pending Arbitration Decision

During the arbitration, unless otherwise ordered by the arbitrators, the Parties shall continue to perform under this Agreement.

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ARTICLE XII
Force Majeure, Non-Normal Conditions, Right to Cure, Termination and Expiration


Section 12.1	Force Majeure and Environmental Force Majeure


(A)	Force Majeure

(1)

Neither Party shall be deemed in default of any obligation under this Agreement, and performance of such obligation shall be excused during such period as and to the extent that performance is prevented by reason of Force Majeure, the term “ Force Majeure ” meaning any cause beyond the control of the Party affected which by exercise of due diligence it shall be unable to overcome, including, without limitation, failure of plant or facilities, flood, earthquake, storm, lightning, fire, explosion, epidemic, war, riot, civil disturbance, labor stoppage, sabotage, or the necessity for compliance with any applicable law, regulation, ordinance or resolution aside from any law, regulation, ordinance or resolution that would otherwise constitute either a Utility Environmental Force Majeure or an SJCC Environmental Force Majeure. Neither Party, however, shall be relieved of liability for failure of performance if such failure is due to causes arising out of its own negligence or to causes which it could, but fails to, remove or remedy with reasonable dispatch. Notwithstanding the foregoing, Utility’s sole remedy with respect to an Environmental Force Majeure is set forth in Section 12.1(B) and SJCC’s sole remedy with respect to an SJCC Environmental Force Majeure is set forth in Section 12.1(C) .

(2)

If a Party’s ability to perform its obligations under this Agreement is affected by Force Majeure, the Party claiming relief (“ Affected Party ”) shall, as soon as practical but no later than five days after the date on which the Affected Party has actual knowledge that the Force Majeure first prevents or delays performance under this Agreement, give notice to the other Party describing in detail the particulars of the occurrence giving rise to the claim, including an estimate of the event’s anticipated duration and effect (if reasonably estimable) upon the performance of its obligations, and any action being taken to avoid or minimize its effect. The Affected Party shall have a continuing obligation to deliver to the other Party regular updated reports and any additional documentation and analysis supporting its claim regarding Force Majeure promptly after such information becomes available to the Affected Party. The Affected Party shall use commercially reasonable efforts to (i) mitigate the duration of, and costs arising from, any suspension or delay in, or other impact to the performance of its obligations under this Agreement and (ii) continue to perform its obligations hereunder not affected by such event. When the Affected Party is able to resume performance of its obligations under this Agreement, the Affected Party shall give the other Party written notice to that effect.

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(3)

In the event that SJCC is prevented from delivering or Utility is prevented from accepting Processed Coal at the Delivery Point(s) due to Force Majeure in accordance with this Section 12.1(A) , Utility’s obligation to make the monthly payment associated with the Tier 1 Tonnage Allocation pursuant to Section 8.1(A) and the payment associated with Annual Preexisting Stockpile Amount pursuant to Section 8.1(B) shall be immediately suspended. Once the impact of the Force Majeure has been remediated and either SJCC is able to resume delivery or Utility is able to resume accepting Processed Coal at the Delivery Point(s), as applicable, Utility’s obligation to make the monthly payment associated with the Tier 1 Tonnage Allocation pursuant to Section 8.1(A) and the payment associated with Annual Preexisting Stockpile Amount pursuant to Section 8.1(B) shall immediately resume. At the end of any Contract Year in which SJCC is prevented from delivering or Utility is prevented from accepting Processed Coal at the Delivery Point(s) due to Force Majeure in accordance with this Section 12.1(A) , SJCC shall determine whether any additional payment is due pursuant to Section 8.7(C) .


(4)	In the event that the Affected Party is prevented from a performing a material obligation under this Agreement due to Force Majeure for a period greater than six (6) months, the other Party shall have the right to terminate this Agreement. In the event of such termination pursuant to this Section 12.1(A)(4) , the rights of the Parties shall be as set forth in Section 12.6(C) .


(5)	If SJCC is prevented from supplying coal to Utility as required under this Agreement due to Force Majeure, Utility may obtain replacement coal from other sources to maintain, but only to the extent that, and for the period during which, SJCC is unable to deliver coal as required under this Agreement.


(B)	Utility Environmental Force Majeure

(1)

In the event Utility reasonably determines that it is unable to comply, or that it is economically impractical to comply, with the interpretation or reinterpretation of existing environmental law or regulation, or any new, amended or modified state, federal and/or local environmental statutes and/or regulations, restraint by court or public authority, or any settlement agreement or other form of compromise or action entered into by Utility to address, or in response to, any legal or regulatory actions affecting the San Juan Station without modifying Utility’s obligations to take coal at the quantities, specifications, and prices provided for in this Agreement (such circumstances collectively referred to as “ Utility Environmental Force Majeure ”), Utility may either terminate this Agreement (such termination to be effective sixty (60) days after notice from Utility) or request a reduction in the Tier 1 Tons; provided, however, such termination or reduction of the Tier 1 Tons shall not occur until the earlier of (i) Utility’s required compliance date with respect to such Utility Environmental Force Majeure

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or (ii) the commercial operation date of any modification made to San Juan Station to allow compliance with such environmental law or regulation in economic manner; provided further that Utility shall be entitled to utilize existing stockpiles of coal prior to termination of this Agreement without such use being a breach of this Agreement. Utility’s notice to SJCC of its intention to terminate the Agreement or its request to adjust the Tier 1 Tons shall include Utility’s analysis regarding the Utility Environmental Force Majeure, including related data, documents, records and spreadsheets regarding Utility’s compliance plans with respect to such environmental laws and/or regulations.

(2)

In the event that Utility requests an adjustment in the Tier 1 Tons, the Parties shall have thirty (30) days from the date of notice to SJCC to negotiate any necessary adjustments to the Tier 1 Price and Tier 2 Price. If the Parties are not able to reach an agreement by the end of such thirty (30) day period, Utility shall be entitled to terminate the Agreement. In the event of such termination by Utility pursuant to this Section 12.1(B)(2) , SJCC’s sole and exclusive remedy shall be as set forth Section 12.6(B) .


(C)	SJCC Environmental Force Majeure

In the event that the interpretation or reinterpretation of existing environmental law or regulation, or any new, amended or modified state, federal and/or local environmental statutes and/or regulations, restraint by court or public authority, or any settlement agreement or other form of compromise or action entered into by SJCC to address, or in response to, any legal or regulatory actions affecting the Coal Leases or SJCC substantially impairs the ability of SJCC to mine Raw Coal (such circumstances collectively referred to as “ SJCC Environmental Force Majeure ”), the following provisions shall apply:


(1)	SJCC shall promptly provide written notice to Utility of the SJCC Environmental Force Majeure (“ SJCC Environmental Force Majeure Notice ”), including a summary of the impact and expected duration of such SJCC Environmental Force Majeure.

(2)

SJCC shall continue to deliver Processed Coal to the Delivery Point(s) in accordance with Section 4.3 utilizing the Reserve of Coal (including the Preexisting Stockpile Coal). For the avoidance of doubt, during such time as the SJCC Environmental Force Majeure substantially impairs the ability of SJCC to mine Raw Coal, the provisions of Section 12.3 shall continue to apply, provided that it shall not be an SJCC Default Condition if the Reserve of Coal is less than five hundred thousand (500,000) tons.


(3)	Commencing immediately upon Utility’s receipt of an SJCC Environmental Force Majeure Notice, Utility’s payment obligations under Sections 8.1(A) – (C) shall cease and, for so long as SJCC is able to deliver Processed Coal to the Delivery Point(s) in accordance with Section 4.3 ,

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Utility shall pay to SJCC on a monthly basis (prorated as necessary based on the date of the SJCC Environmental Force Majeure Notice) for tons of Acceptable Coal delivered to the Delivery Point(s) as follows:

(i)

The Parties shall determine the amount of the Preexisting Stockpile Coal deemed to remain on the Reserve of Coal as of the date SJCC Environmental Force Majeure Notice by subtracting the total amount of tons of Preexisting Stockpile Coal paid for by Utility pursuant to Section 8.1(B) (irrespective of actual deliveries) from the total Preexisting Stockpile Volume (such difference being the “ Available Preexisting Stockpile Tons ”). The “ Available Force Majeure Tons ” shall be determined by subtracting the Available Preexisting Stockpile Tons from the actual Reserve of Coal as of the date of the SJCC Environmental Force Majeure Notice.


(ii)	In the event that Utility receives written notice of an SJCC Environmental Force Majeure on or before December 31, 2017, the following additional payment provisions will apply:


i.	For all Acceptable Coal delivered at the Delivery Point(s) in such month up to the Monthly Preexisting Stockpile Amount, Utility shall pay an amount equal to the actual amount of tons of Acceptable Coal delivered at the Delivery Point(s) multiplied by the SJCC Environmental Force Majeure Price.

ii.

For all Acceptable Coal delivered at the Delivery Point(s) in such month in excess of the Monthly Preexisting Stockpile Amount (such excess tons the “ Force Majeure Tons ”), Utility shall pay an amount equal to the Force Majeure Tons multiplied by the Tier 1 Price; provided that Utility shall only pay for Force Majeure Tons at the Tier 1 Price until the cumulative amount of such Force Majeure Tons is equal to the Available Force Majeure Tons. Any tons delivered to the Delivery Point(s) during an SJCC Environmental Force Majeure in excess of the Available Force Majeure Tons shall be paid for by Utility at the SJCC Environmental Force Majeure Price.


(iii)	In the event that Utility receives written notice of an SJCC Environmental Force Majeure on or after January 1, 2018, the following additional payment provisions will apply:


i.	For all Acceptable Coal delivered at the Delivery Point(s) in such month up to the Monthly Preexisting Stockpile Amount, Utility shall pay an amount equal to the actual

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amount of tons of Acceptable Coal delivered at the Delivery Point(s) multiplied by the Reduced Price.

ii.


(4)	Immediately upon cessation of the SJCC Environmental Force Majeure, SJCC shall provide written notice to Utility and the payment obligation set forth in Sections 12.1(C)(3)(ii) shall cease and Utility shall resume payments to SJCC pursuant to Sections 8.1(A) – (C) (prorated as necessary based on the date of such notice).

(5)

If the SJCC Environmental Force Majeure has not been remediated and the Reserve of Coal has been exhausted and SJCC is no longer able to deliver Processed Coal in accordance with Section 4.3 , the Agreement shall immediately be deemed terminated unless otherwise agreed to by the Parties. In the event of such termination pursuant to this Section 12.1(C)(5) , the rights of the Parties shall be as set forth in Section 12.6(C) .


Section 12.2	Non-Normal Conditions, Right to Cure, and Offers of Non-SJCC Coal .

The Parties intend that in the effort to avoid SJCC Default, the provisions of this Section 12.2 shall be utilized before notice of SJCC Default Conditions (defined in Section 12.3(A) ) is provided pursuant to Section 12.3(C) .


(A)	Non-Normal Conditions . Non-Normal Conditions exist when any of the following three conditions are present:


(1)	SJCC fails to maintain the Reserve of Coal at a level equal to or greater than the Required Reserve,


(2)	SJCC has determined that there is a reasonable probability that the Reserve of Coal will in the near future fall below Required Reserve, or


(3)	SJCC anticipates or is experiencing any other condition that may prevent SJCC from delivering coal according to this Agreement.


(B)	Notice . SJCC shall provide written notice to Utility if any Non-Normal Conditions exist, or the Joint Committee may determine that Non-Normal Conditions exist,

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which shall constitute notice to SJCC and Utility as of the date of such written determination.


(C)	Prevention Due to Force Majeure . In addition to providing written notice of Non-Normal Conditions, SJCC may elect to declare that the performance is prevented by reason of Force Majeure in accordance with the terms of Section 12.1 .


(D)	Coal Usage Forecast . Within fifteen (15) days after receipt of notice of Non-Normal Conditions, Utility will review dispatch at San Juan Station and provide to SJCC an updated coal usage forecast.

(E)

Cure of Non-Normal Conditions . The Parties intend that cooperation among the Parties in developing and agreeing upon a Cure Plan (as defined below) is preferable to pursuing termination of this Agreement. The Parties will provide reasonable cooperation to facilitate SJCC’s cure of Non-Normal Conditions to avoid SJCC Default while allowing Utility to continue operation of the San Juan Station. To initiate and effectuate cure of the Non-Normal Condition, SJCC shall do the following:


(1)	Provide within fifteen (15) days after notice of Non-Normal Conditions, or as otherwise agreed to by the Parties, a written cure plan to the Joint Committee describing SJCC’s proposed means of curing the Non-Normal Conditions and its proposed deliveries in the interim (“ Cure Plan ”);


(2)	Within thirty (30) days after notice of Non-Normal Conditions, or as otherwise agreed to by the Parties, SJCC may provide written offers to Utility to supply Non-SJCC Coal. SJCC will provide coal quality information for the Non-SJCC Coal with the written offers and will propose the delivery schedule and quantity of Non-SJCC Coal to be supplied.


(3)	Within fifteen (15) days after receipt of a proposed Cure Plan, the Joint Committee shall meet to consider and act on the Cure Plan.


(4)	Within fifteen (15) days after receipt of an offer to supply Non-SJCC Coal, the Joint Committee will meet to approve or reject the Non-SJCC Coal offer. Failure to approve the offer shall constitute its rejection.


(5)	For offers of Non-SJCC Coal only, such Non-SJCC Coal shall have an average heating value of not less than 9,100 BTU per pound, as received, averaged over any twenty-four (24) hour period.


(6)	As part of its Cure Plan, SJCC will provide weekly written notice to Utility of daily inventory levels of the Reserve of Coal.


(F)	Rejection of Non-SJCC Coal after Initial Approval . If Utility determines and the Joint Committee agrees that delivery of coal from a certain Non-SJCC Coal source is shown to materially impair operations at the San Juan Station, Utility may reject the unburned portion of that coal and, if so, SJCC shall terminate delivery of that

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coal. The remainder of such rejected coal shall not be credited as coal delivered for purposes of determining whether a SJCC Default Condition exists.


(G)	Termination of Non-Normal Conditions . The Non-Normal Conditions will terminate when all of the following occur:


(1)	The Reserve of Coal exceeds the Required Reserve and;


(2)	SJCC resumes delivery of Processed Coal to Utility at the Delivery Point(s).


Section 12.3	SJCC Default .


(A)	SJCC Default Conditions. The existence of any of the following material default conditions (“ SJCC Default Conditions ”) may result in a SJCC Default by SJCC:


(1)	Failure of SJCC to deliver Processed Coal to the Delivery Point(s) as specified by Utility pursuant to Section 4.3 such that:


(i)	A ten percent (10%) per month or greater shortfall in deliveries of Processed Coal to the Delivery Point(s) as specified by Utility pursuant to Section 4.3 occurs in any six (6) consecutive months; or


(ii)	A cumulative shortfall of sixty percent (60%) in deliveries of Processed Coal to the Delivery Point(s) as specified by Utility pursuant to Section 4.3 occurs over any three (3) month period;


(2)	Delivery to the Delivery Point(s) of Non-Conforming Coal on five (5) occasions during any thirty (30) day period;


(3)	Failure to maintain the insurance required under Section 14.6 and Exhibit F ;


(4)	Failure to maintain the Guaranty as required under this Agreement;


(5)	SJCC is more than twenty (20) days overdue respecting payments due to Utility under this Agreement and no written notification of dispute is provided regarding the payment in question;


(6)	SJCC or Guarantor files a petition or otherwise commences, authorizes or acquiesces in any cause or action under any bankruptcy or similar law for the protection of creditors or has a petition filed against it;


(7)	SJCC or Guarantor makes an assignment or any general arrangement for the benefit of creditors;


(8)	SJCC or Guarantor is unable to pay its debts as they fall due;


(9)	A receiver or receiver-manager is appointed for the business, property, affairs or revenues of SJCC or Guarantor; or

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(10)	Failure of SJCC to maintain a Reserve of Coal greater than the five hundred thousand (500,000) tons when the Required Reserve is more than five hundred thousand (500,000) tons; or


(11)	Termination of either the Reclamation Services Agreement or the CCR Disposal Agreement by Utility due to a “Service Provider Event of Default” (as such term is used in each agreement, respectively);


(B)	SJCC Default exists when (i) either of the conditions described in Section 12.3(A)((10) or (11) occurs or (ii) one or more of the SJCC Default Conditions described in Section 12.3(A)(1) - (9) exists and:


(1)	Notice is provided pursuant to Section 12.3(C) , and,


(2)	SJCC fails to avoid SJCC material default under Section 12.3(D) .

(C)

Notice of SJCC Default Condition(s) . Upon notice from Utility of the occurrence of any of the SJCC Default Conditions specified above in Section 12.3(A)(1) - (4) , SJCC may seek to avoid or cure the SJCC Default Condition(s) pursuant to the provisions of Section 12.3(D) . SJCC shall not be deemed in SJCC Default if SJCC disputes the existence of any alleged SJCC Default unless and until there is a final resolution pursuant to Section 11.1 of this Agreement to determine the existence or non-existence of SJCC Default.


(D)	Avoidance of SJCC Default . SJCC can prevent any of the SJCC Default Conditions specified above in Section 12.3(A)(1) - (4) from becoming a SJCC Default by any one or more of the following actions:


(1)	SJCC proceeds with due diligence to cure the SJCC Default Condition(s) and cures the SJCC Default Condition(s) within thirty (30) days after receipt of the notice of SJCC Default Condition(s);


(2)	Guarantor proceeds with due diligence to cure the SJCC Default Condition(s) and cures the SJCC Default Condition(s) within thirty (30) days of receipt of the notice of SJCC Default Condition(s);


(3)	SJCC declares prevention of performance by reason of Force Majeure pursuant to Section 12.1 , and that declaration is not subsequently invalidated by arbitration;


(4)	SJCC gives notice of Non-Normal Conditions and operates according to a Cure Plan approved by the Joint Committee; or


(5)	SJCC disputes the existence of SJCC Default Condition(s), and there is a final resolution pursuant to Section 11.1 that SJCC was not in SJCC Default hereunder.

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(E)

Utility’s Remedies for SJCC Default . Upon a SJCC Default caused by (i) the existence of any of the SJCC Default Conditions described in Section 12.3(A)(1) - (4) that is not avoided pursuant to Section 12.3(D) or (ii) the occurrence of either of the conditions described in Section 12.3(A)(5) or (6) , Utility may terminate this Agreement and, in addition to any other remedies available at law or equity, Utility may exercise the purchase right set forth in Section 12.6(D) .


Section 12.4	Utility Default .


(A)	The existence of any of the following material default conditions (“ Utility Default Conditions ”) may result in a Utility Default:


(1)	Utility fails to comply with a material obligation of Utility under this Agreement;


(2)	Utility is more than twenty (20) days overdue respecting payments due to SJCC under this Agreement and no written notification of dispute is provided regarding the payment in question;


(3)	Utility files a petition or otherwise commences, authorizes or acquiesces in any cause or action under any bankruptcy or similar law for the protection of creditors or has a petition filed against it;


(4)	Utility makes an assignment or any general arrangement for the benefit of creditors;


(5)	Utility is unable to pay its debts as they fall due;


(6)	A receiver or receiver-manager is appointed for the business, property, affairs or revenues of Utility; or


(7)	Termination of either the Reclamation Services Agreement or the CCR Disposal Agreement by SJCC due to a “Utility Event of Default” thereunder (as such term is used in each agreement, respectively).


(B)	Utility Default exists when (i) the Utility Default Condition in Section 12.4(A)(7) occurs, or (ii) any one of the Utility Default Condition in Sections 12.4(A)(1) - (6) occurs and:


(1)	Notice is provided pursuant to Section 12.4(C) , and


(2)	Utility fails to avoid Utility Default under Section 12.4(D) .

(C)

Notice of Utility Default Condition(s) . Upon notice from SJCC of the occurrence of a Utility Default Condition under Sections 12.4(A)(1) - (6) , Utility may seek to avoid or cure the Utility Default Condition pursuant to the provisions of Section 12.4(D) . Utility shall not be deemed in Utility Default if Utility disputes the existence of any alleged Utility Default unless and until there is a final resolution

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pursuant to Section 11.1 of this Agreement to determine the existence or non-existence of Utility Default.


(D)	Avoidance of Utility Default. Utility can prevent the Utility Default Condition specified above in Sections 12.4(A)(1) - (6) from becoming a Utility Default by any one or more of the following actions:


(1)	Utility proceeds with due diligence to cure the Utility Default Condition and cures the Utility Default Condition within thirty (30) days after receipt of the notice of Utility Default Condition; or


(2)	Utility disputes the existence of Utility Default Condition, and there is a final resolution pursuant to Section 11.1 that Utility was not in Utility Default hereunder.

(E)

SJCC Remedies for Utility Default. Upon a Utility Default caused by (i) the existence of the Utility Default Condition described in Sections 12.4(A)(1) - (6) that is not avoided pursuant to Section 12.4(D) or (ii) the occurrence of the Utility Default Condition described in Section 12.4(A)(7) , SJCC may terminate this Agreement and SJCC’s sole and exclusive remedy shall be as set forth in Section 12.6(A) .


Section 12.5	Utility’s Purchase Right Upon Expiration of the Term

(A)

In the event that the Agreement is not extended in accordance with Section 2.5 , Utility shall have the right but not the obligation to acquire, directly or through an assignee, SJCC and SJTC, the form of which transaction shall be a stock purchase agreement in form reasonably acceptable to the Parties, with a tax basis step-up for federal income tax purposes. Utility must provide written notice of its election to purchase SJCC on or before December 31, 2019.

(B)

The purchase price under such stock purchase agreement shall be the sum of any Unrecovered Capital Expenditures by SJCC since the Effective Date plus or minus a working capital adjustment as of the date of such stock purchase agreement that consists of accounts receivable, inventories (not already billed to under this agreement), prepaid assets net of accounts payable and accrued liabilities. SJCC and SJTC will be transferred free and clear of any debts, liens or encumbrances of any kind under an acquisition under this Section 12.5 . “ Unrecovered Capital Expenditures ” shall mean SJCC’s capital expenditures for each Contract Year in connection with this Agreement (as recorded on SJCC’s financial statement in accordance with United States Generally Accepted Accounting Principles) multiplied by the percentage specified for each Contract Year in the table below multiplied by.

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Contract Year	Applicable Unrecovered Capital Expenditures Percentages
2016	10%
2017	15%
2018	20%
2019	25%
2020	50%
2021	75%
2022	100%


Section 12.6	Termination and Remedy


(A)	Termination by SJCC Due to Utility Event of Default

In the event of a termination of the Agreement by SJCC due to a Utility Event of Default pursuant to Section 12.4(E) , Utility shall, as SJCC’s sole and exclusive remedy, pay to SJCC an amount equal to (i) the “Purchase Price” under the SPA (exclusive of any Working Capital Purchase Price Adjustments) multiplied by the factor set forth on Exhibit J that corresponds to the month in which the Agreement is terminated pursuant to Section 12.4(E) .


(B)	Termination by Utility Due to Utility Environmental Force Majeure

In the event of a termination of the Agreement by Utility due to Utility Environmental Force Majeure pursuant to Section 12.1(B)(1) or (2) , Utility shall, as SJCC’s sole and exclusive remedy, pay to SJCC an amount equal to the “Purchase Price” under the SPA (exclusive of any Working Capital Purchase Price Adjustments) multiplied by the factor set forth on Exhibit K that corresponds to the month in which the Agreement is terminated pursuant to Section 12.1(B)(1) or (2) .


(C)	Termination Due to SJCC Environmental Force Majeure; Termination to by either Party Due to Force Majeure

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In the event of a termination of the Agreement pursuant to Section 12.1(C)(5) or in the event of a termination by either Party due to Force Majeure pursuant to Section 12.1(A)(4) , neither Party shall have any further liability to the other; provided that both Parties shall make any accrued and unpaid payments due as of the date of notice of termination.


(D)	Termination by Utility Due to SJCC Event of Default

In the event of a termination of the Agreement by Utility due to an SJCC Event of Default pursuant to Section 12.3(E) , in addition to any rights available at law or equity, Utility shall have the right, but not the obligation, to acquire, directly or through an assignee, SJCC and SJTC, the form of which transaction shall be a stock purchase agreement in form reasonably acceptable to the parties, with a tax basis step-up for federal income tax purposes. Utility must provide notice of its intent to exercise such right no later than one (1) month after notice of termination pursuant to Section 12.3(E) . The purchase price for such acquisition shall be equal to (i) the “Purchase Price” under the SPA (exclusive of any Working Capital Purchase Price Adjustments) multiplied by the factor on Exhibit L that corresponds with the month in which the Agreement is terminated pursuant to Section 12.3(E) .


Section 12.7	Termination Remedies in the Event of Extension Term

The Parties acknowledge and agree that in the event that the Parties reach agreement with respect to an Extension Term pursuant to Section 2.5 , the remedies set forth in Sections 12.5 and 12.6 shall also be amended as agreed to by the Parties in order to reflect the Extension Term.

ARTICLE XIII
Indemnity


Section 13.1	General Indemnification .

(A)

SJCC shall indemnify and save Utility and its employees, directors, officers, agents, successors, assigns and affiliates harmless from, and shall defend them against, any and all claims, demands or liabilities arising out of the operations of SJCC under this Agreement at the San Juan Station site or the SJCC Site Area, excepting those claims, demands or liabilities arising out of the acts of Utility, their employees, agents, contractors, and representatives.

(B)

Utility shall indemnify and save SJCC and its employees, directors, officers, agents, successors, assigns and affiliates harmless from, and shall defend them against, any and all claims, demands or liabilities arising out of the operations of Utility under this Agreement at the San Juan Station site or the SJCC Site Area, excepting those claims, demands or liabilities arising out of the acts of SJCC, its employees, agents, contractors and representatives.


(C)	If a court of competent jurisdiction determines that the provisions of N.M.S.A. §56-7-1 or 2, (1978 Comp.) are applicable to this Agreement, then only to the

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extent that the indemnification provided in this Agreement or any portion of the indemnification provided in this Agreement would be deemed void or unenforceable under said statutes and to the narrowest extent possible, that portion of the Agreement shall not extend to indemnify against liability, claims, damages, losses or expenses, including attorneys’ fees, for or arising out of:


(1)	In the case that N.M.S.A. §56-7-1, is so determined to be applicable,


(i)	bodily injury to persons or damage to property caused by or resulting from, in whole or in part, the negligence, act or omission of the indemnitee, its officers, employees or agents; and,


(2)	In the case that N.M.S.A. §56-7-2, is so determined to be applicable,


(i)	the sole or concurrent negligence of the indemnified party or the agents or employees of the indemnified party or any independent contractor who is directly responsible to the indemnified party; or


(ii)	any accident which occurs in operations carried on at the direction or under the supervision of the indemnified party or an employee or representative of the indemnified party or in accordance with methods and means specified by the indemnified party or employees or representatives of the indemnified party.

ARTICLE XIV
General Provisions


Section 14.1	Compliance with Applicable Laws

SJCC shall conduct all of its operations under this Agreement in full compliance with all applicable laws, ordinances, regulations and directives of any and all governmental authorities having jurisdiction over such operations in conformity with the provisions of all licenses, permits and approvals; provided, however, that nothing herein shall be construed as prohibiting SJCC from contesting any such law, ordinance, regulation or directive or the provisions of any such license, permit or approval by appropriate judicial or administrative proceedings.


Section 14.2	Labor Force


(A)	SJCC shall comply with the requirements of all civil rights statutes and other federal and state employment laws which may be applicable to its operations under this Agreement.


(B)	During the performance of this contract SJCC agrees as follows:


(1)	SJCC and all of its subcontractors shall abide by the provisions of Executive Order 11246, 41 C.F.R. Sections 60-1.4(a), 1.7(a), 4.2(d), 29

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C.F.R. Part 471, Appendix A to Subpart A, and 48 C.F.R. § 52.222-54, incorporated herein by reference.


(2)	41 C.F.R. 60-300.5(a). SJCC and all of its subcontractors shall abide by the requirements of 41 C.F.R. Section 60-300.5(a). This regulation prohibits discrimination against qualified protected veterans and requires affirmative action by covered prime contractors and subcontractors to employ and advance in employment qualified protected veterans.


(3)	41 C.F.R. 60-741.5(a). SJCC and all of its subcontractors shall abide by the requirements of 41 C.F.R. Section 60-741.5(a). This regulation prohibits discrimination against qualified individuals on the basis of disability, and requires affirmative action by covered prime contractors and subcontractors to employ and advance in employment qualified individuals with disabilities.


(4)	SJCC will include the provisions of Sections 14.2(B)(1) through (3) in all of its subcontracts or purchase orders unless exempted by the applicable law from doing so, so that such provisions will be binding upon each subcontractor or vendor.


Section 14.3	Confidentiality / Non-disclosure

The terms and conditions, including those dealing with compensation, set forth in this Agreement are considered by Utility and SJCC to be confidential and proprietary information and none of the Parties shall disclose any such information to any third party other than the attorneys, auditors, lenders and agents of Utility, other owners of San Juan Station, and SJCC, without the advance written consent of the other Parties; provided, however, disclosure may be made without advance consent where, in the opinion of counsel, such disclosure may be required by order of court or regulatory agency, law or regulation or in connection with judicial or administrative proceedings involving a party hereto, in which event the party to make such disclosure shall advise the other in advance as soon as possible and cooperate to the maximum extent practicable to minimize the disclosure of any such information (including, where practicable, deletion of portions of this Agreement, and, specifically, Section 8.1 ). In addition, either Party (or its affiliates) may disclose this Agreement in filing reports and information with the Securities and Exchange Commission (including without limitation, in a prospectus filing) but shall exercise commercially reasonable efforts to maintain the confidentiality of such information.

Utility shall maintain with the owners of the San Juan Station written confidentiality agreements that are acceptable to SJCC prior to the disclosure of the terms of this Agreement.


Section 14.4	Permits and Approvals

SJCC shall be required to acquire any and all permits, licenses and approvals required by any governmental agency or regulatory body to enable SJCC to carry on the operations

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contemplated by this Agreement, including but without limitation, permits under the “Surface Mining Control and Reclamation Act of 1977” (Pub.L. 95-87, August 3, 1977); provided however, that Utility will cooperate fully with SJCC and supply information necessary to obtain all permits, licenses and approvals.


Section 14.5	Waivers

A waiver by a party at any time of its rights with respect to a default under this Agreement, or with respect to any other matter in connection with this Agreement, shall not be deemed a waiver with respect to any other subsequent default or matter. No delay, short of the statutory period of limitation in asserting or enforcing any right hereunder shall he deemed a waiver of or limitation on such right.


Section 14.6	Insurance

SJCC shall maintain insurance in accordance with the requirements of Exhibit F .


Section 14.7	Notices

(A)

Any notice, demand or request provided for in this Agreement, or given or made in connection with this Agreement, except those normal exchanges of information required by the Mining Oversight Committee and the Joint Committee, shall be in writing, signed by an officer of the party giving such notice and shall be deemed to be properly and sufficiently given or made if sent by registered or certified mail, and if to SJCC, addressed as follows:

Westmoreland Coal Company

Attn: Joe Micheletti, EVP US Operations

200, 9540 South Maroon Circle

Englewood, CO 80112-5730

with a copy addressed as follows:

Westmoreland Coal Company

Attn: Lynette Stanley-Maddocks, General Counsel

200, 9540 South Maroon Circle

Englewood, CO 80112-5730

and if to Utility, addressed as follows:

Public Service Company of New Mexico

Attn: Patrick Apodaca, General Counsel

414 Silver Ave SW

Albuquerque, NM 87102-3289

with a copy addressed as follows:

Public Service Company of New Mexico

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Attn: Chris Olson, Vice President-Generation

414 Silver Ave SW

Albuquerque, NM 87102-3289


(B)	Any party hereto may change its address for notice by so advising the other Parties hereto in accordance with the provisions of this Section 14.7 . Any notice given in accordance with the provisions of this Section 14.7 shall be deemed effectively given as of the date of its deposit with the United States Postal Service.


(C)	Exchanges of information required by the Mining Oversight Committee and the Joint Committee shall be by procedures set forth by the respective committee.


Section 14.8	Choice of Law

The terms and provisions of this Agreement shall be interpreted and construed in accordance with the laws of the State of New Mexico, without regard to conflict of law principles.


Section 14.9	Assignment


(A)	This Agreement may not be assigned by a Party without the consent of the other Party, provided that such consent shall not be unreasonably withheld.


(B)	Any party hereto may without the consent of any other party, assign this Agreement to a majority-owned subsidiary or to a wholly-owned subsidiary of its parent provided that the assigning party shall guarantee performance of this Agreement by such subsidiary.


Section 14.10	Successors and Assigns

Subject to Section 14.9 , this Agreement and all of the obligations and rights herein established shall extend to and be binding upon, and shall inure to the benefit of, the respective successors and assigns of the respective Parties.


Section 14.11	Authorizations

The execution and performance by the Parties of this Agreement have been duly authorized for each party by all necessary corporate action, require no other authorization, consent or approval and do not contravene any law or contractual restriction binding on the Parties.


Section 14.12	Amendments

This Agreement may be amended only by written instrument executed by all of the Parties and any such amendment may be executed in any number of counterparts, and it shall not be necessary that the signatures of all Parties be contained on any counterpart. Each counterpart shall be deemed an original, but all counterparts together shall constitute one and the same instrument.

Page 46

Coal Supply Agreement


Section 14.13	Construction

The terms and conditions of this Agreement are the result of negotiation and drafting on an equal footing by the Parties and their legal counsel. This Agreement shall be construed evenhandedly and without favor or predisposition to any party. The titles of sections in this Agreement have been inserted as a matter of convenience or for reference only, and they shall not control or affect the meaning or construction of any of the terms and provisions hereof.


Section 14.14	Entire Agreement

This Agreement supersedes all prior agreements and representations between the Parties, whether written or oral, with respect to the subject matter of this Agreement and is intended as a complete and exclusive statement of the terms of the agreement between the Parties with respect to the subject matter. Except as specifically set forth in this Agreement, no representations have been made to induce any of the Parties to enter into this Agreement. All Exhibits are incorporated by reference as part of this Agreement.


Section 14.15	Limitation on Damages .

Except to the extent that (i) damages claimed by third parties for which a Party has a duty to indemnify hereunder as expressly provided in this Agreement are shown to be consequential in nature, or (ii) damages are attributable to a Party’s fraud or willful misconduct, notwithstanding anything else in this Agreement to the contrary, neither Party shall be liable to the other Party for any loss, damage or other liability otherwise equivalent to or in the nature of any indirect, incidental, consequential, exemplary, punitive or special damages arising from performing or a failure to perform any obligation under this Agreement.


Section 14.16	Severability

In the event that any of the terms or conditions of this Agreement, or the application of any such term or condition to any person or circumstance, shall be held invalid by an arbitration panel constituted under this Agreement or any court having jurisdiction in the premises, the remainder of this Agreement, and the application of such terms or conditions to persons or circumstances other than those as to which it is held invalid, shall not be affected thereby, except that the provisions in the remainder of this Agreement shall be construed, and modified where necessary, to effectuate the intentions of the Parties and provide them with the benefit of their bargain.


Section 14.17	Survival of Provisions

The Parties agree that those provisions that describe the Parties’ post-expiration and post-termination rights and obligations, including Section 7.4 , shall survive termination or expiration of this Agreement. In addition, those provisions and Exhibits referenced in, or necessary to implement, the provisions that describe the Parties’ post-termination or post-expiration rights and obligations also shall survive.

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Coal Supply Agreement

ARTICLE XV

Signatures

IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed on their behalf by their respective officers, thereunto duly authorized.



PUBLIC SERVICE COMPANY OF NEW MEXICO By:____ /s/ Chris M. Olson __________________ Name: ____ Chris M. Olson ________________ Title: _____ Vice President, Generation ________
WESTMORELAND COAL COMPANY By _____________________________________ Name: __________________________________ Title: ___________________________________

[SIGNATURE PAGE TO COAL SUPPLY AGREEMENT]

Coal Supply Agreement

ARTICLE XV
Signatures

IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed on their behalf by their respective officers, thereunto duly authorized.



PUBLIC SERVICE COMPANY OF NEW MEXICO By:______________________________________ Name: ____ _____________ __________________ Title: ____________________________________
WESTMORELAND COAL COMPANY By:_____ /s/ Jennifer Grafton _________________ Name: ____ Jennifer Grafton _________________ Title: _____ Secretary, SR. VP ________________

[SIGNATURE PAGE TO COAL SUPPLY AGREEMENT]

Coal Supply Agreement

ATTACHMENT 1—FORM OF GUARANTY

THIS GUARANTY , made as of July 1, 2015, by Westmorland Coal Company, a Delaware corporation (“Guarantor”).

W I T N E S S E T H

WHEREAS , as of the “Effective Date” under the Coal Supply Agreement of even date herewith by and between Public Service Company of New Mexico (“Utility”) and Guarantor (“Agreement”), San Juan Coal Company, a Delaware corporation (“SJCC”), shall become a wholly owned subsidiary of Guarantor and shall, among other things, sell to Utility certain quantities of coal to be mined, processed, and delivered pursuant to the Agreement; and

WHEREAS , prior to entering into the Agreement, Utility required that Guarantor guaranty SJCC’s performance of SJCC’s obligations under the Agreement; and

WHEREAS , Guarantor is willing to Guaranty SJCC’s performance of its obligations under the Agreement;

NOW, THEREFORE , to induce Utility to enter into the Agreement and for other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Guarantor hereby agrees with each of Utility severally as follows:


1.	Guaranty.

1.1.

Effective as of the Effective Date (as that term is defined in the Agreement), Guarantor hereby unconditionally and absolutely guaranties to Utility and their respective successors and permitted assigns timely and complete payment and performance of all of SJCC’s obligations under the Agreement and all other present or future agreements and instruments between Utility and Contractors in connection with the performance of the Agreement (all of the foregoing the “ Agreement Documents ”), all whether presently existing or from time to time hereafter created, incurred or arising and including, without limitation, any interest accrued on such amounts pursuant to the Agreement Documents (such obligations of SJCC collectively the “ Obligations ”). This Guaranty is a continuing guarantee, and shall apply to all Obligations whenever arising.

1.2.

Guarantor hereby agrees that its obligations hereunder shall be absolute and unconditional irrespective of (i) any insolvency, bankruptcy, reorganization or dissolution, or any proceeding in respect of any thereof, of SJCC or Guarantor, (ii) the validity, regularity or enforceability (except to the extent that the Agreement would not have been enforceable against Guarantor had it, rather than SJCC, been the primary obligor thereunder) of obligations of SJCC under the Agreement or the extension or renewal thereof, in whole or in part, with or without notice to or assent from Guarantor, (iii) any alteration, amendment, modification, extension, renewal, release, change, waiver or consent in respect of any of the terms, covenants, or conditions contained in the Agreement, or (iv) the absence of notice, other than notice required by the terms of the Agreement, or the absence of or any delay in any action to enforce any obligation or to exercise any right or remedy against SJCC or Guarantor, whether hereunder or under the Agreement, or any indulgence or extension granted to or compromise with SJCC or Guarantor, or any action or proceedings

Attachment 1—Page 1

Coal Supply Agreement

taken or not taken with respect to or by or on behalf of SJCC or Guarantor or (v) any circumstance whatsoever (including, without limitation, any statute of limitations) or any act of the Utility or any existence of or reliance on any representation by the Utility that might otherwise constitute a legal or equitable defense available to, or a discharge of, the Guarantor.

1.3.

Guarantor hereby (i) waives diligence, presentment, demand of payment, filing of claims with a court in the event of the merger or bankruptcy of SJCC, any right to require a proceeding first against SJCC, or to realize on any collateral, protest, notice and all demands whatsoever, with respect to the obligations of SJCC, (ii) agrees that its obligations hereunder constitute guaranties of performance and not of collection and are not in any way conditional or contingent upon any attempt to collect from or enforce against SJCC or upon any other condition or contingency, (iii) agrees that its obligations hereunder shall continue to be effective if at any time the obligations of SJCC under the Agreement are rescinded or modified or limited in connection with any bankruptcy or reorganization or other similar proceedings, and (iv) covenants that this Guaranty will not be discharged except by complete performance of SJCC’s obligations under and contained in the Agreement. Without limiting the generality of the preceding clause (ii), Guarantor specifically agrees that it shall not be necessary or required and that it shall not be entitled to require that Utility or either of them file suit or proceed to obtain or assert a claim for any judgment against SJCC or make any effort to enforce the Agreement or exercise or assert any other right or remedy to which Utility or either of them is or may be entitled in connection with the Agreement or any security or Guaranty or assert or file any claim against the assets of SJCC or any other person before or as a condition of enforcing the liability of Guarantor under this Guaranty or at any time thereafter


2.	Miscellaneous


2.1.	This Guaranty is made to Utility solely for their benefit and may not be assigned by Utility except in connection with and contemporaneously with an assignment of the Agreement as permitted therein, and any other purported assignment shall be void and of no force and effect.

2.2.

Guarantor agrees that it will maintain its corporate existence, will not dissolve or otherwise dispose of all or substantially all of its assets and will not consolidate with or merge into another corporation; provided, however, that Guarantor may consolidate with or merge into, or sell or otherwise transfer all or substantially all of its assets as an entirety (and may thereafter dissolve) to, another corporation incorporated and existing under the laws of the United States or one of the states thereof, provided that, in the event that Guarantor is not the surviving, resulting or transferee corporation, as the case may be, such corporation, prior to such merger, consolidation, sale or transfer, assumes, by delivering to Utility an instrument in writing satisfactory in form and substance to Utility, all of the obligations of Guarantor herein.


2.3.	No remedy herein conferred upon Utility is intended to be exclusive of any other available remedy or remedies, but each and every such remedy shall be cumulative and shall be in

Attachment 1—Page 1

Coal Supply Agreement

addition to every other remedy given under this Guaranty or now or hereafter existing at law or in equity.

2.4.

The obligations of Guarantor hereunder shall be continuing and irrevocable. This Guaranty constitutes the entire agreement and supersedes all prior agreements and understandings both written and oral among Guarantor and Utility with respect to the subject matter hereof. No modification or waiver hereof shall be binding upon Utility or Guarantor unless such modification or waiver shall be in writing and signed by an officer of each of Utility and of Guarantor.

2.5.

This Guaranty shall be construed in accordance with and governed by the laws of the State of New Mexico. Wherever possible each provision of this Guaranty shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Guaranty shall be prohibited by or invalid under such law, such provisions shall be ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Guaranty. THE GUARANTOR HEREBY IRREVOCABLY WAIVES ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM (WHETHER BASED ON CONTRACT, TORT OR OTHERWISE) ARISING OUT OF OR RELATING TO, THIS GUARANTY, OR THE ACTIONS OF THE BENEFICIARY IN THE NEGOTIATION, ADMINISTRATION, PERFORMANCE OR ENFORCEMENT THEREOF.


2.6.	Each and every default of SJCC in performance of any obligation under the Agreement shall give rise to a separate cause of action hereunder, and separate suits may, but need not, be brought hereunder as each claim or cause of action arises.


2.7.	All payments by Guarantor to Utility shall be made in the [__________] in United States Dollars and shall be paid within fifteen (15) days after receipt by Guarantor from Utility of written demand for such payment and shall not be the subject of any offset against any amounts which may be owed by Utility to Guarantor.


2.7.	Guarantor agrees to pay all costs, expenses and fees, including all reasonable attorneys’ fees, which may be incurred by Utility in enforcing this Guaranty, whether by suit or otherwise, to the extent Utility is the prevailing party.


2.8.	This Guaranty shall terminate automatically in the event the Agreement is terminated prior to the “Effective Date” under the Agreement.


2.9.	For purposes of notice under this Guaranty, Guarantor’s address is as follows:

Westmoreland Coal Company

Attn: Joe Micheletti, EVP US Operations

200, 9540 South Maroon Circle

Englewood, CO 80112-5730

And

Westmoreland Coal Company

Attachment 1—Page 1

Coal Supply Agreement

Attn: Lynette Stanley-Maddocks, General Counsel

200, 9540 South Maroon Circle

Englewood, CO 80112-5730

The Utility’s addresses are as follows:

Public Service Company of New Mexico

Attn: Patrick Apodaca, General Counsel

414 Silver Ave SW

Albuquerque, NM 87102-3289

And

Public Service Company of New Mexico

Attn: Chris Olson, Vice President-Generation

414 Silver Ave SW

Albuquerque, NM 87102-3289

Any notice provided for in this Guaranty shall be in writing, signed by an officer of the party giving such notice and shall be deemed to be properly and sufficiently given or made if sent by registered or certified mail to the above address or such substitute address as provided in writing pursuant to this notice provision.

[ Remainder of page intentionally blank ]

Attachment 1—Page 1

Coal Supply Agreement

IN WITNESS WHEREOF, Guarantor has caused this Guaranty to be executed on its behalf by its officers thereunto duly authorized.

WESTMORELAND COAL COMPANY

By: _____________________________________

Name: ___________________________________

Title: ____________________________________

ATTEST:

By: _____________________________________

Name: ___________________________________

Title: ____________________________________

Attachment 1—Page 1

Coal Supply Agreement

EXHIBIT A—COAL LEASES

Detailed Descriptions are attached. Note that the map above presents a more detailed view of the area designated as the San Juan Mine in the map contained in Exhibit E.

Exhibit A Page 1

Coal Supply Agreement

Coal Lease Description

NM 28093 – Federal Coal Lease, the Deep Lease, approx. 3,855.60 acres.

Township 30 North, Range 15 West, NMPM, (Non-Fruitland)

Section 13: S½

Section 14: S½

Section 23: All

Section 24: All

Section 25: All

Section 26: All

Section 35: Lots 1 (44.33), 2 (44.07),

3 (43.73), 4 (43.37), N½,

N½S½

NM 99144 – Federal Coal Lease, the Deep Lease Extension, approx. 4,483.88 acres.

Township 30 North, Range 14 West, NMPM, (Non-Fruitland)

Section 17: All

Section 18: All

Section 19: All

Section 20: All

Section 29: All

Section 30: All

Section 31: Lots 1 (41.70), 2 (41.21),

3 (40.73), 4 (40.24), N½,

N½S½

A Portion of NM 045196 – Federal Coal Lease, approx. 75.19 acres.

Township 29 North, Range 15 West, NMPM, (South Lease Ext. - Non-Fruitland)

Section 3: Pt. Lot 7 (NW¼NE¼),

Pt. Lot 8 (NE¼NW¼),

Pt. Lot 9 (NW¼NW¼)

Township 30 North, Range 15 West, NMPM, (Fruitland)

Section 33: Pt. SE¼SE¼

Those parcels above being more particularly

described as follows:

Beginning at the northwest corner of Section 3,

T. 29 N., R.15 W., N.M.P.M.;

thence S00°28’13”W, a distance of 1223.85 feet;

thence S81°49’59”E, a distance of 279.99 feet;

Exhibit A Page 2

Coal Supply Agreement

A Portion of NM 045196 – Federal Coal Lease, approx. 75.19 acres. (Con’t)

thence S87°50’12”E, a distance of 171.09 feet;

thence N00°00’00”E, a distance of 408.87 feet;

thence S90°00’00”E, a distance of 1272.03 feet;

thence S75°37’07”E, a distance of 365.81 feet;

thence S90°00’00”E, a distance of 781.39 feet;

thence S33°41’24”E, a distance of 196.56 feet;

thence S89°45’27”E, a distance of 263.83 feet;

thence S00°31’00”E, a distance of 182.86 feet;

thence S89°18’31”E, a distance of 704.68 feet;

thence N00°10’29”E, a distance of 1260.42 feet;

thence N89°04’25”W, a distance of 1290.76 feet;

thence S00°13’34”W, a distance of 343.77 feet;

thence N90°00’00”W, a distance of 2044.33 feet;

thence N00°02’37”W, a distance of 357.63 feet;

thence N88°45’04”W, a distance of 592.41 feet

to the Point of Beginning. Containing 74.3010 acres,

more or less.

Also;

Beginning at a point on the East line of Section 33,

T. 30 N., R 15 W., N.M.P.M.,

thence S70°37’18”W, a distance of 89.22 feet;

thence S01°00’25”W, a distance of 420.49 feet;

thence S87°59’32”E, a distance of 93.85 feet to the

southeast corner of said Section 33;

thence N00°17’00”W, a distance of 453.33 feet to

the Point of Beginning. Containing 0.8916 Acres,

more or less.

Exhibit A Page 3

Coal Supply Agreement

A portion of NM 045197 – Federal Coal Lease, approx. 670.91 acres.

Township 30 North, Range 15 West, NMPM, (Fruitland)

Section 22: Pt. S½S½,

Section 27: Pt. N½, SE¼

Section 34: Pt. SW¼SW¼, E½,

Township 29 North, Range 15 West, NMPM, (South Lease Ext. Non-Fruitland)

Section 3: Lot 6 (NE¼NE¼), SE¼NE¼

Those parcels above being more particularly

described as follows:

Beginning at the Northeast corner of

Section 27, T. 30 N., R. 15 W., N.M.P.M.;

thence N00°27’12”E, a distance of 805.00 feet

thence S89°59’17”W, a distance of 4,161.17 feet;

thence S00°00’00”W, a distance of 781.39 feet;

thence S48°32’17”E, a distance of 1,133.68 feet;

thence S00°11’29”E, a distance of 1,348.21 feet;

thence S90°00’00”E, a distance of 1,599.12 feet;

thence S00°00’00”W, a distance of 7,559.47 feet;

thence N90°00’00”W, a distance of 944.93 feet;

thence S00°08’59”E, a distance of 931.45 feet;

thence S89°12’51”E, a distance of 1,289.64 feet;

thence S00°10’29”W, a distance of 1,260.42 feet;

thence S00°59’47”W, a distance of 1,307.15 feet;

thence S88°51’08”E, a distance of 1,316.41 feet;

thence N00°47’13”E, a distance of 1,318.24 feet;

thence N00°47’10”E, a distance of 1,246.49 feet;

thence N00°26’01”W, a distance of 2,718.01 feet;

thence N00°10’44”E, a distance of 5,256.20 feet;

thence N00°44’15”E, a distance of 2,640.08 feet

to the Point of Beginning. Containing 663.1875

acres, more or less.

Also;

From a Point of Beginning on the South Section line

of Section 34, T. 30 N., R. 15 W., N.M.P.M.;

thence N00°01’23”E, a distance of 678.17 feet;

thence S70°37’18”W, a distance of 631.11 feet;

thence S00°17’00”E, a distance of 453.33 feet to

the southwest corner of Section 34, T. 30 N.,

R. 15 W., N.M.P.M.;

thence S88°30’30”E, a distance of 593.05 feet

to the Point of Beginning containing 7.7182 acres, m/l.

Exhibit A Page 4

Coal Supply Agreement

Brimhall, Ralph L., et al Fee Leases, approx. 5.17 acres.

Township 29 North, Range 15 West, NMPM, (Non-Fruitland - SLE)

Section 3: Pt. SW¼NE¼

More particularly described as follows:

Beginning at the Point of Beginning;

thence S01°15’10”E, a distance of 324.92 feet;

thence S90°00’00”E, a distance of 699.61 feet;

thence N00°22’42”W, a distance of 316.34 feet

to the center of the northeast ¼ of Section 3,

T. 29 N., R. 15 W., N.M.P.M.;

thence N89°18’31”W, a distance of 704.68 feet

to the Point of Beginning.

San Juan Coal Company & Crook, Bonnie V. Kennedy, et al Fee Leases, approx. 2.8 acres.

Township 29 North, Range 15 West, NMPM. (Fruitland)

Section 4: Pt. NE¼NE¼

More particularly described as follows:

Beginning at the northeast corner of

Section 4, T. 29 N., R. 15 W., N.M.P.M.

thence N86°28’24”W, a distance of 94.55 feet;

thence S01°00’25”W, a distance of 1,214.65 feet;

thence S81°49’59”E, a distance of 106.75 feet;

thence N00°28’13”E, a distance of 1,223.85 feet

to the Point of Beginning.

MC 0087 - State of New Mexico Coal Lease

Township 30 North, Range 14 West, NMPM, approx. 650.80 acres

Section 32: Lots 1 (43.27), 2 (42.89),

3 (42.51), 4 (42.13), N ½ ,

N ½S ½

MC 0088 - State of New Mexico Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 649.20 acres

Section 36: Lots 1 (40.57), 2 (41.73).

3 (42.87), 4 (44.03), N½,

N ½S ½

HC-0004 New Mexico State Coal Lease

Township 29 North, Range 15 West, NMPM, approx 278.28 acres

Section 2: Lots 1, 2, 3, 4, S½NE¼, SE ¼NW¼

Exhibit A Page 5

Coal Supply Agreement

NM 28093 Mod 1 – April 2006 modification to Federal Coal Lease NM 28093, the Deep Lease, approx. 160.6 acres.

Township 29, North, Range 15 West, NMPM, approx. 160.6 acres

Section 1: Lots 3-4, S/2NW/4

NM 28093 Mod 2 – Modification to Federal Coal Lease NM 28093, the Deep Lease, approx. 448.36 acres. [A5]

Township 29 North, Range 15 West, NMPM, approx. 127.46 acres

Section 1: Gov’t Lot 1, Gov’t Lot 2, SE/4 NE/4, E/2 E/2 SW/4 NE/4

Township 29 North, Range 14 West, NMPM, Approx. 320.9 acres

Section 6: N/2

Exhibit A Page 6

Coal Supply Agreement Exhibit B

EXHIBIT B—DELIVERY POINTS

Exhibit B Page 1

Coal Supply Agreement

EXHIBIT C—MINING PLANS AND METHODS

Introduction and Commitment to Safe Operating Practices

In the event of any conflict or inconsistency between any projections or assumptions in this Exhibit C and any other term or condition of the Coal Supply Agreement, such other term or condition of the Coal Supply Agreement shall control. This Exhibit C shall not in any way modify the obligations of the Parties that are otherwise specified in the Coal Supply Agreement. The mining plans and methods associated with the San Juan Underground Mine and coal leases are based on Prudent Mining Practices, as defined in the Coal Supply Agreement.

SJCC is committed to operating the mine in a safe, legal, and efficient manner. The mine will be operated in accordance with the safety standards and regulations as mandated by the U.S. Mine Safety and Health Administration (MSHA) and the State of New Mexico, and will also comply with company standards when such standards exceed those of regulatory agencies.

The mine will operate in accordance with the MSHA-approved Roof Control Plan and Ventilation Plan as required in 30 CFR 75.220 and 75.370, respectively. These plans shall be reviewed and submitted on a semi-annual basis per 30 CFR 75, and will be updated on an as-needed basis when mining conditions dictate.

The control of mine gases will be maintained at the operations through existing practices, including, but not limited to: providing adequate ventilation to the mine workings to dilute concentrations of mine gases, installation and maintenance of Gob-Vent-Boreholes (GVB) to exhaust gases, and nitrogen injection into sealed gob areas to provide an inert atmosphere and reduce the potential for spontaneous combustion

A state-of-the-art communications and tracking system will be maintained at all times during operations of the mine. SJCC’s Emergency Response Plan (ERP) shall be maintained and updated on an ongoing basis; this plan will be approved by MSHA in accordance with the ERP requirements for post-accident-communication and electronic tracking systems required by the Mine Improvements and New Emergency Response Act of 2006 (MINER Act).

Additionally, the mine will staff and maintain at least one properly trained Mine Rescue Team as required by 30 CFR Part 49 at all times while the mine continues to operate.

Exhibit C Page 1

Coal Supply Agreement

Mine Planning

Underground mining is conducted in the Number 8 Seam of the Fruitland Coal formation. The primary production method is longwall (LW) mining and development is performed using room and pillar methods with continuous miner (CM) sections of equipment. Underground access is provided via drift openings in the existing highwall of the previously mined Juniper Open Pit surface operations. Additionally, a set of portals associated with San Juan Pilot Mine were previously utilized, but these mine portals have since been abandoned and sealed. The Juniper Pit provides access to the underground main entries for materials and personnel transportation, coal conveyance, ventilation, and support services.

Figure 1 illustrates the existing mine workings and the projected mining sequence of future mining areas. The main entries support underground infrastructure and the LW and CM activities. The interconnected series of gateroads define the individual LW panels; groups of adjacent panels are described as LW mining districts. Current mining activity is situated in the 400 district in the northern portion of the mine. Annual mining plans are designed and prepared to indicate where CM development and LW mining will occur. Figure 1 is illustrated as follows:

Exhibit C Page 2

Coal Supply Agreement

Continuous Mining Methods

The opening dimensions at SJCC can vary with conditions/purpose, but are typically 9 to 12 feet high and 18 to 20 feet wide, which is conducive to stable mine openings and efficient operations. A typical CM production section will include a CM machine, a roof bolting machine, and two to four coal haulage machines (ram cars). Existing mining equipment is consistent with state-of-the-art industry practice and is properly designed for efficient and productive mining activities. The mining process itself is regarded as simple and utilizes basic mining concepts.

A CM is used to extract the coal seam by mining a “cut”, which is the width of the opening (18 to 20 feet) and extended to the desired depth. The cut depths vary with mining conditions, and the maximum depth is defined by the approved roof control plan (up to 30 feet).

The CM is equipped with a rotating head that cuts a rectangular profile into the face of the coal seam. The fractured material includes coal, partings and out-of-seam dilution (OSD, the extraneous non-coal roof and floor material that is inherently extracted during the mining process). The CM gathers the fractured coal and then uses an internal conveyor to load the material into a haulage car that has a payload of 12 to 18 tons. The filled ram car carries the product from the miner to a “feeder,” where the coal is discharged from the car and metered onto a conveyor belt for transport out of the mine.

The empty ram car then trams back to the miner to be reloaded. While this cycle is taking place, a second ram car is subsequently loaded. This cycle continues until the cut is fully extracted. The ram cars are then routed to the next face to be mined. The CM machine backs out of the freshly-mined cut and trams to the next location in the cycle.

A roof bolting machine then trams into the freshly extracted cut and supports the immediate roof. This is accomplished by drilling holes into the mine roof and installing roof bolts, which are steel rods that strengthen the integrity of the roof. As roof bolting proceeds, the auxiliary ventilation tubing is extended into the cut to ventilate the face. As the bolter backs out of the entry, rock dust is applied. The face is then ready for the next cut as the CM progresses through the mining cycle.

Other ancillary equipment is utilized at SJCC to support the CM production sections, including cleanup and supply scoops, transport vehicles, power systems, etc. The following illustration provides a perspective view of a CM development unit:

Exhibit C Page 3

Coal Supply Agreement

Longwall Mining Methods

The CM units extract only 5% to 15% of the mine’s output. The majority of production is mined by the LW unit. The LW is a sophisticated and highly mechanized mining system that incorporates engineering designs with high safety factors for motors, horsepower ratings, chain strengths, and structural capacity. The face features a 4,160‑volt electrical supply and hydraulic lines pumped from the surface. Primary LW components consist of:


•	Shields: Each of these state-of-the-art, hydraulically powered, 2-leg supports measures 1.75 meters in width (5 ft 9 in) and has 1,150 tons of capacity. The practical mining height range is 8 to 13 feet, even though the physical operating range for the shields is 6.1 ft to 14.5 ft.


•	Armored Face Conveyor: Commonly referred to as the panline, and is comprised of steel sections that are joined to permit a degree of lateral movement as mining advances. The joints are connected over the length of the 1,000‑ft face and the chain conveyor is powered by high-horsepower drives at each end of the face.


•	Shearer: The cutting and loading machine that traverses the length of the armored face conveyor to cut the coal from the LW face in 1-meter swaths. The machine utilizes rotating cutting drums at each end to efficiently cut coal in each direction. The shearer and shields have an integrated control system.


•	Stageloader: The transition section that crushes the coal and transfers the mined material from the armored face conveyor to the belt conveyor.

The LW panels are developed off the main entries. An individual longwall panel consists of a large rectangular block of coal outlined by gate roads and the set-up face. Each set of gate roads consists of three entries developed by the CM units. LW panels at SJCC

Exhibit C Page 4

Coal Supply Agreement

measure up to 15,000 feet long, 1,000 feet wide and 8 ft to 13 ft thick. The longest panel can contain 9 million tons of coal, making the SJCC panels among the largest in the US coal industry. The massive size of the panels is conducive to high levels of efficiency, as it minimizes the percentage of higher-cost CM tons in the total product, and maximizes overall mining time between LW moves.

After the LW equipment is installed along the 1,000-foot end of the block, the shearer trams along the face conveyor and cuts one-meter deep swaths of coal from the face at a mining height of 8 to 13 feet. As coal is removed, each shield systematically lowers slightly (drops away from the roof) and is advanced forward and re-pressurized against the roof. The panline is advanced forward, and the cycle repeats. The area behind the roof supports collapses as the roof supports are advanced. This collapsed area behind the shields, where the coal has been removed, is called the gob.

The physical and chemical properties of the coal and the gob at SJCC are prone to spontaneous combustion. SJCC’s mine design is focused on managing spontaneous combustion considerations to minimize the risk of an event. SJCC utilizes a progressive sealing system in its ventilation system as the LW face retreats; seals are built in each crosscut so as to prevent airflow across the gob. The mine also utilizes the injection of nitrogen from a nearby production facility to inert the atmosphere behind the LW shields and in the gob itself.

The general layout of the San Juan longwall face is similar to other high capacity faces of recent manufacture located at highly productive western US mining operations. A simplified schematic of the face is shown below:

Exhibit C Page 5

Coal Supply Agreement

Miscellaneous

Conveyance : The level grade of the property (less than 3%) facilitates a simple and reliable belt conveyor system. SJCC utilizes 750-hp belts in the main entries and 500‑hp modules in the panel belts. The system is designed to convey 4,200 tph in the LW gate belts and 6,600 tph in the main conveyor system. These design ratings are for normal loading with proper clearance distances along the belt edges. The motors and belting material strengths have been designed around the ability to convey a fully loaded, edge-to-edge, load of material.

Mine Dewatering : The main dewatering system consists of a sump with two borehole pumps located near the bottom of the first ventilation shaft. The sump is fed by a system of submersible pumps, tanks and discharge lines located throughout the mine workings. The mine dewatering system capacities are 250 gpm from each working section, 750 gpm in the mains and 1,000 gpm from the main sump to the surface, as has been demonstrated to successfully dewater the mine.

Compressed Air : A mine-wide distribution system is installed with main compressors located on the surface to reduce underground fire hazards. There is room for three compressors in the building and connections for a fourth diesel compressor outside the building. They are sized so that two of the three run at any one time and can meet the projected demands of the mine.

Rock Dust System : The utilization of rock dust, or pulverized limestone, to inert the combustibility of coal dust, is a key part of safety compliance in the U.S. The top layer (up to 1” thick) of material on the roof, ribs and floor are sampled, analyzed and compared to statutory standards for combustibility. The presence of thin layers of fine coal dust on any surface is also prohibited.

Electrical Distribution : SJCC is fed by a 69,000-volt line from the generating station, with redundant transformers and transmission lines available in case of failure.

Ventilation : SJCC operates in accordance with the approved Ventilation Plan to dilute gases, carry away dust, and provide a safe and productive working environment.

Operating Projections

LW mining is recognized as the safest, most productive, and lowest-cost form of underground coal mining. These efficiencies are achieved through rigid adherence to

Exhibit C Page 6

Coal Supply Agreement

long-term mining plans that are relatively inflexible. Mine development must be planned and initiated years in advance of LW production activities, and there is minimal opportunity to make meaningful changes in mine layout or design in the short to intermediate term (less than three years).

Mine scheduling and associated production levels at SJCC are not based on the capacity or operational potential of the mine. Instead, mine planning is directly proportional to the fuel supply needs of the San Juan Generating Station. The projected future tonnage (annual output) is significantly below the optimum output of the mine if it were to operate in an unconstrained market. The following table summarizes annual mine performance through 2021:



	Mine Planning Parameters
	2015	2016	2017	2018	2019	2020	2021
LW Retreat (feet)	12,800	9,247	9,069	6,158	6,631	6,416	5,987
CM Gate Devel (feet)	17,224	14,118	16,000	5,882	—	—	—
CM Mains Devel (feet)	1,894	1,297	—	—	—	—	—

Annual Production (000 tons)	7,038	5,140	5,032	3,252	3,249	3,170	2,880

The mining plans and corresponding projections at the San Juan Mine through 2021 are largely established by decisions made by SJCC throughout the previous decade. Key assumptions for the 2015 calendar year are as follows; provided that, for the avoidance of doubt, neither Party shall be excused from performing its other obligations under the Coal Supply Agreement in the event that actual conditions differ from any of the assumptions set forth in this Exhibit C :


1.	Mine layout, mining plans, and production sequences reflect the BHP/SJCC plans provided in early 2015. BHP/SJCC adheres to these plans throughout 2015.


2.	Based on the projections provided by BHP Billiton, the Pre-Existing Stockpile at SJCC is 4.8 million tons on January 1, 2016.


3.	All future coal production at SJCC (exclusive of Pre-Existing Stockpile tons) is assumed to be at 9,100 Btu/lb.


4.	The entirety of the Pre-Existing Stockpile is assumed to be 9,000 Btu/lb.


5.	Coal quality of actual stockpiles and future production will vary from the assumptions presented herein. Coal quality estimates are being revised based on ongoing analysis of geological/quality data provided by BHP/SJCC.


6.	The primary driver for projections of coal production and stockpile withdrawals is the 2016–2022 Burn Forecast for San Juan Generating Station. This was provided

Exhibit C Page 7

Coal Supply Agreement

by San Juan Generating Station in accordance with Section 7.2.C.1.i of the Coal Supply Agreement for purposes of developing the 2016 Annual Operating Plan.


7.	Physical withdrawals from the Pre-Existing Stockpile are based on meeting total deliveries to SJGS per the 2016‑2022 Burn Forecast as provided by SJGS and the estimated production from the SJCC mine.


8.	Withdrawals from the Pre-Existing Stockpile are at the projected withdrawals as identified by Utility. These withdrawals are identified on a monthly basis during 2016, on a quarterly basis in 2017, and annually thereafter.

Actual future coal production will not precisely match the monthly, quarterly, and annual station consumption, respectively (less stockpile withdrawals), due to inherent fluctuations in the mining process associated with mining operational factors and geological conditions; provided that, for the avoidance of doubt, SJCC shall at all times remain obligated to deliver coal at the Delivery Point in accordance with Article IV of the Coal Supply Agreement and maintain the Reserve of Coal as specified in the Coal Supply Agreement.


10.	Coal production activities are sequenced as illustrated in the attached Figure 1.

11.

Based on the projections provided by BHP Billiton the approximate extents of mine workings as of December 31, 2015 were identified as shown in Figure 1. The location of the longwall face in the LW‑402 Panel is approximately 10 crosscuts from the recovery room. Continuous miner development of the GR‑403 entries will be completed, and the Set-Up Rooms (SR-403) will be two‑thirds completed. Continuous miner development of the GR‑404 entries will be advanced approximately 3,000 feet from the West Sub-Mains. Continuous miner development of the West Sub-Mains shall be sufficiently extended to enable both the GR‑403 entries and the West Sub-Mains development units to operate simultaneously (separate ventilation circuits).


12.	BHP/SJCC does not mine any portion of SR‑404 (the Set-Up Rooms for the LW‑404 Panel) prior to January 1, 2016. This enables SJCC to lengthen or shorten the subject LW‑404 Panel, if desired by SJCC, to enhance mining performance while meeting coal consumption needs at SJGS.

Key Assumptions: 2016

13.

Westmoreland takes control of SJCC on January 1, 2016. At that point in time, the LW is operating in Panel LW-402 and will be nearing completion of mining in that panel. Coal production largely ceases in March/April of 2016 as the LW is moved to Panel LW‑403 (the only exception being minor quantities of CM development coal). For planning purposes, the LW move is assumed to be completed by the end of April, and LW production resumes in May. Coal delivery to SJGS in March/April will essentially be from the Pre-Existing Stockpile.

Exhibit C Page 8

Coal Supply Agreement

14.

Following the completion of the LW move, mining in Panel LW‑403 panel will commence and routine production activities resume. Coal production in 2016 is supplemented by 1.5 million tons of coal withdrawal from the Pre-Existing Stockpile. Given the lower tonnage demand, the LW operates at a reduced schedule in comparison to historical norms. LW retreat (total feet mined) in 2016 is lower than prior years of operation.


15.	After CM development of the West Sub-Mains entries is completed, the only development activities will be CM extension of the remaining gate entries.

16.

CM development of the GR-404 section continues through 2016. The proposed mining plan has some flexibility in that, upon reaching the Set-up Room (SR–404) as highlighted below, SJCC can decide whether to adjust the length of Panel LW‑404 (to some extent) also Panel LW‑405. This extension of GR‑404 must be completed before the LW mining starts in the Panel LW‑404, as the CM section cannot physically operate beyond the LW face once LW‑404 commences mining in 2017. If the additional reserves to the east are to be exploited beyond the proposed mining layout (extension to a 2035 Mine Plan), Panel LW‑405 would be shortened to the same length as the prior panels in the 400 district. Otherwise, sterilization of reserves will occur. Mining progress in 2015 and 2016 are illustrated below:

Key Assumptions: 2017


17.	The LW will continue mining in Panel LW‑403 until it is exhausted in the third quarter. The LW will then be moved to LW‑404. Mining in Panel LW‑404 begins around the start of the fourth quarter and continues through year end.


18.	Annual production is coordinated with the SJGS consumption forecast and it is assumed that 1.5 million tons will be delivered from the Pre-Existing Stockpile. At the end of 2017, the coal stockpile will be approximately 2 million tons.

Exhibit C Page 9

Coal Supply Agreement


19.	The CM unit completes development of the GR‑404 gate. Thereafter, the only CM development in the plan is the extension of the GR‑405 entries.

Key Assumptions: 2018 and Beyond


20.	Coal production rate is reduced to about 3.2 million tons per year in 2018 and thereafter.


21.	After the CM development has been completed in GR‑405 in 2018, production activities are limited to LW operations. Support for maintenance of the mine in the outby areas, conveyor systems, and ventilation network will still be necessary but a significantly reduced staffing level can be utilized.


22.	In mid-2019 the LW will be transferred to Panel LW‑405, where it will operate through 2021.

There are ample coal reserves that would support extension of mine workings into the 500 and 600 districts and could provide coal supply to SJGS for another 10 to 15 years. Development of these areas requires extension of the East Main entries. In order to maintain the continuity of production activities after LW mining is completed in Panel LW‑405, ample notice (at least three years) is required. This lead time is necessary to rehabilitate the East Main entries, extend the East Main entries, and develop the headgate and tailgate entries of future LW panels.

Exhibit C Page 10

Coal Supply Agreement

EXHIBIT D—PROJECTED ANNUAL TONNAGE



Year	Tier 1 Tons (in millions)	Forecasted Tier 2 Tons (in millions)	Total Forecasted Tons (in millions)
2016	5.75	0.65	6.4
2017	5.75	0.65	6.4
2018	2.8	0.4	3.2
2019	2.8	0.4	3.2
2020	2.65	0.55	3.2
2021	2.65	0.55	3.2
2022	1.4	0.2	1.6

Exhibit D Page 1

Coal Supply Agreement

EXHIBIT E—SJCC SITE AREA

Detailed descriptions are attached

Exhibit E Page 1

Coal Supply Agreement

SJCC Site Area Description

SAN JUAN MINE

NMSF 071448 – Federal Coal Lease

Township 29 North, Range 15 West, NMPM, approx. 40.00 acres

Section 4: SW¼NW¼

NM 045196 – Federal Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 2,409.14acres

Section 2: N½NW¼, NW¼NE¼

Section 3: NE¼NE¼

Section 9: W½NW¼

Section 10: W½

Section 21: All

Section 28: All

Section 33: Lots 1 (38.90), 2 (37.51),

3 (36.11), 4 (34.72), N½, N½S½;

Township 29 North, Range 15 West, NMPM, approx. 154.10acres

Section 3: Lots 7 (37.84), 8 (38.15), and 9 (38.11)

Section 4: SE¼NE¼

Except a tract of land in the NW¼NW¼

Section 21, T30N-R15W identified as the

‘PNM Pond’ and more particularly described

as follows:

Commencing at the Point of Beginning

from which the northwest corner of said Section 21,

bears N06º07’47”W, 590.47 feet;

thence S85º50’42”E, a distance of 397.22 feet;

thence N52º45’07”E, a distance of 51.53 feet;

thence S60º41’12”E, a distance of 937.42 feet;

thence S00º25’43”E, a distance of 315.45 feet;

thence N87º44’41”W, a distance of 670.35 feet;

thence N49º57’34”W, a distance of 71.49 feet;

thence N01º32’04”W, a distance of 381.28 feet;

thence N83º15’01”W, a distance of 554.64 feet;

thence N06º26’49”E, a distance of 254.89 feet to

the Point of Beginning, and

Exhibit E Page 2

Coal Supply Agreement

NM 045196 – Federal Coal Lease (Con’t)

Except a tract of land in the NW¼ Section

33, T30N-R15W, identified as the ‘Red Clinker

Area’ and more particularly described as follows:

Tract 1: Beginning at the East 1/4 corner of

Section 32;

thence N, 1,160 feet to the Point of Beginning:

thence S90º00’00”E, a distance of 2,200.00 feet;

thence N00º00’00”E, a distance of 770.00 feet;

thence N90º00’00”W, a distance of 2,196.92 feet;

thence S00º13’45”W, a distance of 770.01 feet

to the Point of Beginning and containing 38.86

acres, more or less.

Tract 2: Beginning at the Southeast corner of

Tract 1 above;

thence N00º00’00”E, a distance of 770.00 feet;

thence S49º26’01”E, a distance of 134.57 feet;

thence S31º34’17”E, a distance of 287.40 feet;

thence S25º57’11”E, a distance of 157.99 feet;

thence S15º16’44”W, a distance of 260.60 feet;

thence S20º43’35”W, a distance of 370.06 feet;

thence S48º32’59”W, a distance of 162.71 feet;

thence S83º09’58”W, a distance of 141.30 feet;

thence N46º12’10”W, a distance of 106.54 feet;

thence N05º33’34”W, a distance of 232.04 feet;

thence N27º18’24”E, a distance of 89.70 feet;

thence N60º33’23”W, a distance of 85.58 feet;

thence S90º00’00”E, a distance of 272.80 feet

to the Point of Beginning and containing 7.45

acres, more or less.

NM 045197 – Federal Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 2,565.60 acres

Section 15: All

Section 22: All

Section 27: All

Section 34: Lots 1 (42.75), 2 (41.85), 3 (40.95),

4 (40.05), N½, N½S½

Township 29 North, Range 15 West, NMPM, approx. 77.52acres

Section 3: Lot 6 (37.52), SE¼NE¼

{ Note : There is no surface agreement on the

SW¼NE¼ Sec. 15, T30N-R15W with surface owner}

Exhibit E Page 3

Coal Supply Agreement

NM 045217 – Federal Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 1,800.00 acres

Section 3: NW¼NE¼, S½NE¼, NW¼, S½

Section 4: SE¼NE¼, SW¼SW¼, E½SW¼, SE¼

Section 9: E½NW¼, E½, SW¼

Section 10: E½

NM 28093 – Federal Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 3,855.60 acres

Section 13: S½

Section 14: S½

Section 23: All

Section 24: All

Section 25: All

Section 26: All

Section 35: Lots 1 (44.33), 2 (44.07),

3 (43.73), 4 (43.37), N½, N½S½

{ Note : There is no surface agreement on the

N½SW¼ Sec. 13, T30N-R15W with surface owner}

NM 99144 – Federal Coal Lease

Township 30 North, Range 14 West, NMPM, approx. 4,483.88 acres

Section 17: All

Section 18: All

Section 19: All

Section 20: All

Section 29: All

Section 30: All

Section 31: Lots 1 (41.70), 2 (41.21),

3 (40.73), 4 (40.24), N½, N½S½

MC 0037 – State of New Mexico Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 309.04 acres.

Section 32: Lots 1 (34.82), 2 (36.31), 3 (37.91),

N½SE¼, NE¼SW¼, NW¼NW¼,

SW¼NE¼

{ Note: The State Land Office is in the process of term-

inating MC 0037 and replacing it by issuing a Surface Use

Lease due to the tract being mined out and now in the

reclamation phase.}

Exhibit E Page 4

Coal Supply Agreement

MC 0083 – State of New Mexico Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 520.00 acres

Section 16: E½NE¼, SW¼NE¼, W½NW¼,

S½

MC 0084 – State of New Mexico Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 120.00 acres

Section 16: E½NW¼, NW¼NE¼

MC 0087 – State of New Mexico Coal Lease

Township 30 North, Range 14 West, NMPM, approx. 650.80 acres

Section 32: Lots 1 (43.27), 2 (42.89),

3 (42.51), 4 (42.13), N½,

N½S½

MC 0088 – State of New Mexico Coal Lease

Township 30 North, Range 15 West, NMPM, approx. 649.20 acres

Section 36: Lots 1 (40.57, 2 (41.73),

3 (42.87), 4 (44.03), N½,

N½S½

Crook, Bonnie V. Kennedy, et al – 8 Fee Coal Leases

Township 29 North, Range 15 West, NMPM, approx. 237.16 acres

Section 4: Tract A : Lots 3 (40.01), 4 (40.21),

SE¼NW¼, SW¼NE¼

Tract B : Lots 1 (39.61), 2 (39.81)

except the easterly 1/32 of Lot 1

The coal rights under the easterly

1/32 of Lot 1 are owned by San

Juan Coal Company, approx. 2.5 acres

Bannowsky, Mary Irene, et al – 5 Fee Coal Leases

Township 29 North, Range 15 West, NMPM, approx. 159.97 acres

Section 5: Lots 1 (40.15), 2 (39.82), S½NE¼

Brimhall, Ralph L., et al – Fee Coal Lease

Township 29 North, Range 15 West, NMPM, approx. 80.00 acres

Section 3: SW¼NE¼, SE¼NW¼

Palmer, Barton L., et al – 5 Fee Coal Leases

Township 29 North, Range 15 West, NMPM, approx. 40.00 acres

Section 3: SW¼NW¼

Exhibit E Page 5

Coal Supply Agreement

Walker, Victor H. et al – 6 Fee Coal Leases

Township 29 North, Range 15 West, NMPM, approx. 15.82 acres

Section 3: All of the E½NW¼SE¼ lying North

of U.S. Highway 64

Brimhall, Karen, Trustee, et al – 11 Fee Coal Leases

Township 29 North, Range 15 West, NMPM, approx. 45.36 acres

Section 3: That part of the W½NW¼SE¼ and

NE¼SW¼ lying North of Highway

64, excepting a parcel in the

W½NE¼SW¼ desc. in Book 314,

Page 361;

That parcel in the W½NE¼SW¼

desc. In Book 314, Page 361, approx. 1.84 acres

{ Note : 50% of the coal rights under B314,

P361 (1.84 acres) are owned by San Juan Coal Company}

Smouse, Samuel T. and Mollie Frances – Fee Coal Lease

Township 29 North, Range 15 West, NMPM, approx. 15.40 acres

Section 3: That part of the NW¼SW¼ lying North

of Highway 64 desc. as follows:

Beginning at the

West ¼ corner of said Section 3,

thence N89º44’00”E a distance of 1,305.70 feet

along the North line of

said NW¼SW¼;

thence S00º37’06”E a distance of 502.00 feet;

thence S89º44’00”W a distance of 1,306.00 feet, more or less, to the West

side of said NW¼SW¼;

thence N00º33’01”W a distance of 502.00 feet to the Point of Beginning.

NM 80733 (Water Impoundment and Haulroad Right-of-Way)

Township 30 North, Range 15 West, NMPM, approx. 113.75 acres

Section 4: S½S½N½NE¼NE¼, S½NE¼NE¼,

S½S½NE¼NW¼NE¼,

S½SW¼NW¼NE¼, SE¼NW¼NE¼,

E½SE¼SW¼NE¼NW¼,

E½SE¼NW¼,

S½SE¼NE¼NW¼,

E½E½W½SE¼NW¼, SW¼NE¼

Exhibit E Page 6

Coal Supply Agreement

NM 26441 (69 kv Powerline Easement)

Township 29 North, Range 15 West, NMPM, approx. 0.86 acres

Section 2: Pt. of Lot 4 described more

particularly as follows:

Beginning at the

southwest corner of Section 35, T30N, R15W,

NMPM, being a BLM brass cap marked

T30N, R15W 35 2 3 34 T29N, R15W 1966;

thence along the northerly section line of said

Section 2 S89º10’54”E a distance of 345.24 feet to a point

on the centerline of a 30 foot electrical

easement and being the “True Point of

Beginning”:

thence continuing along the centerline

S20º27’05”E a distance of 39.30 feet;

thence continuing along the centerline

S20º54’52”E a distance of 516.11 feet;

thence continuing along the centerline

S51º46’42”W a distance of 325.55 feet;

thence continuing along the centerline

S55º38’08”W a distance of 363.77 feet.

Plant and Maintenance Facilities Area

(formerly Ground Lease Agreement - PNM/TEP to SJCC)

Township 30 North, Range 15 West, NMPM, approx. 95.93 acres

Sections 20 and 29:

A tract described as

commencing at the Point of Beginning from

which the West ¼ corner of Section 28, T30N,

R15W, NMPM, bears S00º13’17”W, 1974.83 feet;

thence N89º41’50”W, a distance of 653.95 feet;

thence N00º13’44”E, a distance of 632.31 feet;

thence N86º54’45”W, a distance of 656.83 feet;

thence N00º06’28”W, a distance of 956.78 feet;

thence N50º38’05”W, a distance of 266.86 feet;

thence N63º31’14”W, a distance of 154.86 feet;

thence N67º51’36”W, a distance of 372.42 feet;

thence N76º04’25”W, a distance of 527.90 feet;

thence S61º06’21”W, a distance of 100.19 feet;

Exhibit E Page 7

Coal Supply Agreement

Plant and Maintenance Facilities Area (Con’t )

thence N10º28’32”W, a distance of 166.18 feet;

thence S69º25’46”E, a distance of 93.01 feet;

thence S81º03’35”E, a distance of 894.85 feet to

a chain link fence corner;

thence N00º08’08”E, a distance of 242.07 feet

along the fence to another fence corner;

thence N81º46’30”E, a distance of 754.68 feet to

another chain link fence;

thence S72º57’52”E, 657.05 feet along a fence line;

thence N01º40’04”E, 90.06 feet along a fence line;

thence N07º14’12”W, 336.64 feet along a fence line;

thence N09º34’59”W, 186.57 feet along a fence line;

thence N89º06’56”E, 120.41 feet along a fence line;

thence N11º34’22”W, 663.23 feet along a fence line;

thence N89º39’56”W, 41.21 feet along a fence line;

thence N10º31’33”W, 70.30 feet along a fence line;

thence N17º19’55”W, 89.42 feet along a fence line;

thence N20º23’16”W, 60.02 feet along a fence line;

thence N23º34’29”W, 522.44 feet along a fence line;

thence N09º18’43”W, 28.92 feet along a fence line;

thence N02º15’30”E, 82.24 feet along a fence line;

thence N48º50’18”E, 179.70 feet along a fence line;

thence N31º46’05”E, 177.25 feet along a fence line;

thence N14º04’54”E, 420.06 feet along a fence line;

thence N56º09’23”E, 130.00 feet along a fence line;

thence N64º24’31”E, 100.08 feet along a fence line;

thence S89º52’45”E, 119.13 feet along a fence line;

thence N06º47’31”E, 355.76 feet along a fence line;

thence N00º14’57”E, 477.00 feet along a fence line;

thence N50º13’45”E, 15.25 feet to the northeast

corner of Section 20, T30N, R15W, NMPM;

thence S00º15’17”W, a distance of 5,265.48 feet to the

southeast corner of said Section 20;

thence S00º13’17”W, a distance of 660.88 feet to the

Point of Beginning.

Exhibit E Page 8

Coal Supply Agreement

Gypsum Haulage Easement (PNM/TEP to SJCC)

Township 30 North, Range 15 West, NMPM, approx. 1.70 acres

Sections 17 and 20: A tract described as

Commencing at the Point of Beginning from

which the northwest corner of Section 21

bears S00º15’31”W, a distance of 170.63 feet;

thence S77º04’32”W, a distance of 325.26 feet;

thence S76º27’03”W, a distance of 427.17 feet;

thence S66º38’30”W, a distance of 254.62 feet;

thence N02º22’16”W, a distance of 129.69 feet;

thence N81º24’59”E, a distance of 219.70 feet;

thence N76º09’13”E, a distance of 440.11 feet;

thence N76º12’46”E, a distance of 336.91 feet to the

west line of Section 16;

thence S00º15’30”W, 74.19 feet along said

west line to the Point of Beginning.

Water Pipeline Easement (Raw Water Pipeline – PNM/TEP to SJCC)

Township 30 North, Range 15 West, NMPM, approx. 1.974 acres

Section 29: Pt. of NE¼ described as follows:

An easement 35 feet wide being 17.5 feet on

each side of the following described centerline:

Beginning at raw waterline tapping point,

whence the one-quarter (¼) corner common to

Sections 28 and 29, T30N-R15W, NMPM,

bears

S65º57’29”E 2,479.39 feet distant; running thence

as an easement S73º27’11”E a distance of 207.51 feet to an

angle point ;

thence S57º48’13”E a distance of 984.76 feet to an angle

point ;

thence S89º17’22”E a distance of 1,230.94 feet to a point on

the east boundary line of said Section 29.

Easement for Waterline (Underground Waterline – PNM/TEP to SJCC)

Township 30 North, Range 15 West, NMPM, approx. 1.510 acres

Section 29: Pt. of NE¼ described as follows:

Beginning at a point on PNM’s water pipeline

from which the East ¼ corner of Section 29,

T30N-R15W, NMPM bears S50º52’55”E

2,923.13 feet distant. Thence, N79º25’46”E

a distance of 1,644.52 feet to the west edge of the PNM

Ground Lease. Said easement being 20 ft.

either side of this line.

Exhibit E Page 9

Coal Supply Agreement

LA PLATA MINE

NM 0315559 – Federal Coal Lease

Township 32 North, Range 12 West, NMPM, approx. 1,964.15 acres

Section 7: Lots 1 (44.18), 2 (44.12),

3 (44.08), SE¼SW¼

Section 8: Lots 5 (34.60), 6 (36.22), 7 (33.60),

8 (33.52)

Section 17: Lots 3 (38.31), 4 (39.18), 5 (38.70)

Section 18: Lots 1 (39.68), 3 (39.18), SE¼NE¼,

NE¼SW¼, N½SE¼

Township 32 North, Range 13 West, NMPM

Section 13: Lots 3 (41.86), 4 (42.21),

5 (42.34), 6 (41.98), 7 (41.57),

8 (41.19), 9 (41.34), 10 (41.72),

11 (42.11), 12 (42.46), S½NW¼

Section 14: S½NE¼, SE¼NW¼, S½

Section 15: That portion of the SE¼ lying

East of State Highway 170

Section 22: E½NE¼

Section 23: N½N½, SW¼NW¼

Chamberlain, Lenore T. Trust, et al Fee Coal Lease

Township 32 North, Range 12 West, NMPM, approx. 490.90 acres

Section 7: S½SE¼

Section 8: Lots 2 (43.58), 3 (43.82), 4 (44.06),

SW¼SW¼

Section 18: E½NW¼, Lot 2 (39.42), SW¼NE¼,

N½NE¼

NM 95280 Right-of-Way (Pits to Stockpile Spoil Area)

Township 32 North, Range 12 West, NMPM, approx. 234.93 acres

Section 7: Lot 5 (39.82)

Section 17: Lots 2 (35.17), 6 (37.83), 12 (38.31)

Township 32 North, Range 13 West, NMPM

Section 13: Lots 1 (42.08), 2 (41.72)

{ Note : Right-of-Way document describes 230 acres

whereas, GLO lot acreages calculates to 234.93 acres.

NM 95280 is outside the leased area but within

the permitted area.}

Exhibit E Page 10

Coal Supply Agreement

LA PLATA TRANSPORTATION CORRIDOR

NM 55331 Right-of-Way Parcel #1 (Facilities Site)

Township 32 North, Range 13 West, NMPM, approx. 309.19 acres

Sections 23 and 24: A tract of land more

specifically described as follows:

Beginning

at a point which is the southeast corner of said

Section 23, thence N00º37’03”W, 573.34 feet which is the true Point of Beginning;

thence N89º04’50”W a distance of 2,868.91 feet;

thence N00º18’26”W a distance of 605.88 feet;

thence N00º18’26”W a distance of 2,276.13 feet;

thence N89º50’32”W a distance of 1,103.93 feet;

thence N00º01’46”W a distance of 500.00 feet;

thence S89º50’32”E a distance of 1,320.30 feet;

thence S89º29’38”E a distance of 2,627.89 feet;

thence N01º11’54”W a distance of 1,329.93 feet;

thence S86º08’05”E a distance of 2,555.17 feet;

thence S71º13’08”W a distance of 619.48 feet;

thence S32º25’20”E a distance of 407.64 feet;

thence S34º28’08”E a distance of 95.13 feet;

thence S57º51’16”W a distance of 495.49 feet;

thence N32º21’19”W a distance of 500.44 feet;

thence S44º17’46”W a distance of 1,525.10 feet;

thence S27º25’53”E a distance of 934.13 feet;

thence S54º16’49”W a distance of 235.52 feet;

thence N86º39’05”W a distance of 669.49 feet;

thence S00º23’38”E a distance of 2,079.72 feet to

the true Point of Beginning.

Note: Except any portion of this parcel that has been transferred by SJCC to San Juan County.

{ Note : Right-of-Way document describes Parcel #1

as having 309.19 acres, whereas the plat and description

describes 306.6 acres.}

NM 55331 Right-of-Way Parcel #4

Township 31 North, Range 13 West, NMPM, approx. 100.68 acres

Section 7: Pt. SW¼ and N½SE¼

Section 8: Pt. NW¼NE¼, SE¼NW¼, and NW¼SW¼

Section 18: Pt. NW¼NW¼ (Lots 5, 6, and 7)

which is more specifically described as follows:

Beginning at a point on the West boundary of said

Section 18 whence the Northwest corner of said

Exhibit E Page 11

Coal Supply Agreement

Section 18 bears N00º55’17”E a distance of 794.74 feet;

thence 460.45 feet along the arc of a curve to the left

which has a radius of 6,893.89 feet, a central

angle of 03º49’37” and a long chord which

bears N49º41’02”E a distance of 460.37 feet

to a point of tangency with a curve to the left;

thence 1,527.76 feet along the arc of said curve

which has a radius of 4,466.65 feet, a central

angle of 19º35’50” and a long chord which

bears N41º47’55”E a distance of 1,520.32 feet;

thence N32º00’00”E a distance of 1,022.45 feet

to a point of tangency with a curve to the right;

thence 1,109.66 feet along the arc of said curve

which has a radius of 2,346.90 feet, a central

angle of 27º05’26” and a long chord which bears

N45º32’43”E a distance of 1,099.35 feet;

thence N30º54’34”W a distance of 50.00 feet to

a non-tangent point of intersection with a curve

concave to the southeast;

thence 977.91 feet along the arc of said curve

NM 55331 Right-of-Way Parcel #4 (Con’t.)

which has a radius of 2,396.90 feet, a central

angle of 23º22’34”E and a long chord which bears

N70º46’43”E and a distance of 971.14 feet;

thence S07º32’00”E, a distance of 50.00 feet;

thence N82º28’00”E, a distance of 292.16 feet to a

point of tangency with a curve to the left;

thence 1,703.31 feet along the arc of said curve

which has a radius of 2,082.99 feet, a central angle

of 46º51’07” and a long chord which bears

N59º02’27”E a distance of 1,656.25 feet;

thence N35º36’53”E, a distance of 2,143.56 feet;

thence S89º29’19”E, a distance of 550.04 feet;

thence S35º36’53”W, a distance of 2,459.87 feet to a

point of tangency with a curve to the right;

thence 2,071.28 feet along the arc of said curve which

has a radius of 2,532.99 feet, a central angle of

46º51’07” and a long chord which bears S59º02’27”W

a distance of 2,014.05 feet;

thence S82º28’00”W a distance of 292.16 feet

to a point of tangency with a curve to the left;

thence 1,670.81 feet along the arc of said curve

which has a radius of 1,896.90 feet, a central

angle of 50º28’00” and a long chord which bears

Exhibit E Page 12

Coal Supply Agreement

S57º14’00”W a distance of 1,617.32 feet;

thence S32º00’00”W a distance of 1,022.45 feet

to a point of tangency with a curve to the right;

thence 1,681.67 feet along the arc of said curve

which has a radius of 4,916.65 feet, a central angle

of 19º35’50” and a long chord which bears

S41º47’55”W a distance of 1,673.49 feet to a point

of tangency with a curve to the left;

thence 866.41 feet along the arc of said curve which

has a radius of 6,443.89 feet, a central angle of

07º42’13” and a long chord which bears S47º44’43”W

a distance of 865.75 feet;

thence N00º55’17”E, a distance of 637.03 feet to the

Point of Beginning.

NM 55331 Right-of-Way, there is not a Parcel #5

NM 55331 Right-of-Way Parcel #6

Township 30 North, Range 14 West, NMPM, approx. 69.58 acres

Section 7: A tract of land in the NW¼SW¼

Township 30 North, Range 15 West, NMPM

Section 12: A tract of land in the SE¼ which

tracts are more specifically described as follows:

Beginning at a point whence the West ¼

Corner of said Section 7, T30N, R14W bears

N89º40’49”W a distance of 75.79 feet;

thence S89º40’49”E, a distance of 1,396.85 feet;

thence S43º51’50”W, a distance of 3,629.37 feet;

thence N89º38’48”W, a distance of 287.20 feet;

thence North a distance of 1,160.56 feet;

thence N43º51’50”E a distance of 2,028.05

feet to the Point of Beginning.

NM 55331 Right-of-Way Parcel #7

Township 30 North, Range 15 West, NMPM, approx. 16.37 acres

Section 13: A tract of land in the N½NW¼,

and the NW¼NE¼ which is more specifically

described as follows:

Beginning at a point whence the Northwest

Corner of said Section 13 bears N00º25’29”E

A distance of 994.58 feet;

thence 772.26 feet along the arc of a curve to the right which

has a radius of 2,404.33 feet, a central angle of

18º24’12” and a long chord which bears

N69º03’46”E a distance of 768.95 feet;

thence N78º15’52”E a distance of 1,064.12 feet

Exhibit E Page 13

Coal Supply Agreement

to a point of tangency with a curve to the left;

thence 1,103.42 feet along the arc of said curve

which has a radius of 2,752.29 feet, a central

angle of 22º58’13” and a long chord which bears

N66º46’46”E a distance of 1,096.04 feet;

thence S89º38’49”E a distance of 365.47 feet

to a non-tangent point intersection with a curve

which is concave to the northwest;

thence 1,493.28 feet along the arc of said curve

which has a radius of 2,977.29 feet, a central angle

of 28º44’14” and a long chord which bears

S63º53’45”W a distance of 1,477.68 feet;

thence S78º15’52”W a distance of 1,064.12 feet

to a point of tangency with a curve to the left;

NM 55331 Right-of-Way Parcel #7(Con’t.)

thence 835.44 feet along the arc of said curve which

has a radius of 2,179.33 feet, a central angle of

21º57’51” and a long chord which bears S67º16’57”W

a distance of 830.33 feet;

thence N00º25’30”E a distance of 266.19 feet to the

Point of Beginning.

NM 55331 Right-of-Way Parcel #8

Township 30 North, Range 15 West, NMPM, approx. 27.30 acres

Section 14: Pt. SE¼SW¼ and W½SE¼

Section 23: Pt. NW¼NW¼ which is more

specifically described as follows:

Beginning at a point whence the Northwest

corner of said Section 23 bears N00º20’11”E

a distance of 948.01 feet;

thence 613.40 feet along the arc of a curve to the left

which has a radius of 5,199.51 feet, a central

angle of 06º45’33” and a long chord which

bears N59º44’19”E a distance of 613.04 feet;

thence N56º21’32”E a distance of 1,032.68

feet to a point of tangency with a curve to the

left;

thence 1,969.96 feet along the arc of said curve

which has a radius of 9,618.05 feet, a central

angle of 11º44’07” and a long chord which bears

N50º29’29”E a distance of 1,966.52 feet;

thence N44º37’25”E a distance of 196.98 feet to

a point of tangency with a curve to the left;

thence 1,545.89 feet along the arc of said curve

which has a radius of 5,617.08 feet, a central angle

Exhibit E Page 14

Coal Supply Agreement

of 15º46’07” and a long chord which bears

N36º44’22”E a distance of 1,541.02 feet;

thence S00º24’38”W a distance of 444.86 feet to a

non-tangent point of intersection with a curve

which is concave to the northwest;

thence 1,216.37 feet along the arc of said curve

which has a radius of 5,842.08 feet, a central angle

of 11º55’46” and a long chord which bears

S38º39’32”W a distance of 1,214.17 feet;

thence S44º37’25”W a distance of 196.98 feet

to a point of tangency with a curve to the right;

NM 55331 Right-of-Way Parcel #8 (Con’t.)

thence 2,016.05 feet along the arc of said curve

which has a radius of 9,843.05 feet, a central angle

of 11º44’07” and a long chord which bears

S50º29’29”W a distance of 2,012.52 feet;

thence S56º21’32”W a distance of 1,032.68 feet

to a point of tangency with a curve to the right;

thence 755.04 feet along the arc of said curve

which has a radius of 5,424.51 feet, a central

angle of 07º58’30” and a long chord which bears

S60º20’48”W a distance of 754.44 feet;

thence N00º20’11”E a distance of 252.30 feet to

the Point of Beginning.

NM 55331 Right-of-Way there is not a Parcel #9

NM 55331 Right-of-Way Parcel #10

Township 30 North, Range 15 West, NMPM, approx. 49.99 acres

Section 22: Pt. N½ which is more specifically

described as follows:

Beginning at a point whence the Northwest

corner of said Section 22 bears N00º09’05”E

a distance of 1,002.94 feet;

thence N87º23’54”E a distance of 349.28 feet

to a point of tangency with a curve to the right;

thence 685.78 feet along the arc of said curve

which has a radius of 1,402.66 feet, a central

angle of 28º00’46” and a long chord which

bears S78º35’43”E a distance of 678.97 feet;

thence S64º35’20”E a distance of 767.42 feet

to a point of tangency with a curve to the left;

thence 693.64 feet along the arc of said curve

which has a radius of 1,505.37 feet, a central

angle of 26º24’02” and a long chord which bears

Exhibit E Page 15

Coal Supply Agreement

S77º47’21”E a distance of 687.52 feet;

thence N89º00’38”E a distance of 524.24 feet

to a point of tangency with a curve to the left;

thence 533.69 feet along the arc of said curve

which has a radius of 1,733.70 feet, a central

angle of 17º38’15” and a long chord which bears

N80º11’31”E a distance of 531.58 feet;

thence N71º22’23”E a distance of 1,152.22 feet

to a point of tangency with a curve to the left;

NM 55331 Right-of-Way Parcel #10 (Con’t.)

thence 781.60 feet along the arc of said curve

which has a radius of 5,112.01 feet, a central

angle of 08º45’37” and a long chord which bears

N66º59’34”E a distance of 780.84 feet;

thence S00º20’11”W a distance of 447.43 feet to

a non-tangent point of intersection with a curve

which is concave to the northwest;

thence 634.56 feet along the arc of said curve

which has a radius of 5,512.01 feet, a central angle

of 06º35’46” and a long chord which bears S68º04’30”W

a distance of 634.21 feet; thence S71º22’23”W a distance

of 1,152.22 feet to a point of tangency with a curve to the right;

thence 656.82 feet along the arc of said curve

which has a radius of 2,133.70 feet, a central angle

of 17º38’15” and a long chord which bears

S80º11’31”W a distance of 654.23 feet;

thence S89º00’38”W a distance of 524.24 feet

to a point of tangency with a curve to the right;

thence 877.95 feet along the arc of said curve

which has a radius of 1,905.37 feet, a central angle

of 26º24’02” and a long chord which bears

N77º47’21”W a distance of 870.20 feet;

thence N64º35’20”W a distance of 767.42 feet to

a point of tangency with a curve to the left;

thence 490.22 feet along the arc of said curve which

has a radius of 1,002.66 feet, a central angle of

28º 00’46” and a long chord which bears

N78º35’43”W a distance of 485.35 feet;

thence S87º23’54”W a distance of 368.52 feet;

thence N00º09’05”E a distance of 400.45 feet to the

Point of Beginning.

NM 55331 Right-of-Way Parcel #11

Township 30 North, Range 15 West, NMPM, approx. 30.02 acres

Section 21: Pt. NW¼ which is more specifically

Exhibit E Page 16

Coal Supply Agreement

described as follows:

Beginning at a point whence the North ¼

corner of said Section 21 bears N00º10’14”E

a distance of 1,179.71 feet;

thence S82º18’16”W a distance of 319.81 feet

to a point of tangency with a curve to the right;

thence 502.06 feet along the arc of said curve

which has a radius of 624.60 feet, a central angle

of 46º03’18” and a long chord which bears

N74º40’07”W a distance of 488.65 feet;

NM 55331 Right-of-Way Parcel #11 (Con’t.)

thence N51º38’24”W, a distance of 666.92 feet;

thence S00º13’07”W, a distance of 508.59 feet;

thence S51º38’30”E, a distance of 536.01 feet;

thence S51º55’57”W, a distance of 1,779.10 feet;

thence S89º36’20”E, a distance of 643.11 feet;

thence N51º55’57”E, a distance of 1,398.79 feet to

a point of tangency with a curve to the right;

thence 390.59 feet along the arc of said curve which

has a radius of 736.84 feet, a central angle of

30º22’19” and a long chord which bears

N67º07’07”E a distance of 386.03 feet;

thence N82º18’16”E a distance of 194.00 feet;

thence N00º10’14”E a distance of 403.80 feet to the

Point of Beginning.

NM 55331 Right-of-Way Parcel #12

Township 30 North, Range 15 West, NMPM, approx. 2.74 acres

Section 21: Pt. SW¼NW¼ which is more

specifically described as follows:

Beginning at a point whence the Northwest

corner of said Section 21 bears N00º16’00”E a

distance of 1,318.35 feet;

thence S89º34’10”E a distance of 147.02 feet;

thence S05º38’47”W a distance of 927.76 feet;

thence S00º18’47”W a distance of 394.39 feet;

thence N89º36’20”W a distance of 59.71 feet;

thence N00º16’00”E a distance of 1,318.35 feet

to the Point of Beginning.

Exhibit E Page 17

Coal Supply Agreement

FEE SURFACE LANDS OWNED BY SAN JUAN COAL COMPANY

(Related to the Transportation ‘Haulroad’ Corridor)

Note: rights-of-way containing the roadway have been transferred by SJCC to San Juan County. SJCC specifically retained all mineral rights and the bulk of the surface estate.

Township 32 North, Range 13 West, NMPM, approx. 240.00 acres

Section 22: S½SE¼SE¼

Section 27: N½NE¼NE¼, NW¼NE¼

NE¼NW¼, W½NW¼, NW¼SW¼

Harris, John E., Trustee, et al

(Transportation ‘Haulroad’ Corridor)

Note: the nothern portion of this right-of-way was transferred by SJCC to San Juan County for use as a public roadway. The southern portion was retained by SJCC. The division line is not exact, but is believed to be accurate to within several feet. Therefore the courses marked with an * are approximate.

Township 31 North, Range 13 West, NMPM, approx. 39.00 acres

Section 4: Pt. SW¼ SW¼NW¼

Section 5: Pt. SE¼NE¼, S½ which is more specifically

described as follows:

Beginning at a point on the

south line of said Section 5, from which the SW

corner of said Section 5 bears N88º04’38”W a

distance of 2,397.63 feet;

thence N35º36’53”E a distance of 2,884.97 feet

to a point of tangency with a curve to the left;

* thence 1,057.26 feet along the arc of said curve

* which has a radius of 11,981.46 feet, a central

* angle of 5º03’21” and a long chord which bears

* N33º05’12”E a distance of 1,056.91 feet;

* thence S52º02’41”E a distance of 453.64 feet

to a non-tangent point of intersection with a curve to the

right;

* thence 1,038.61 feet along the arc of said curve

*which has a radius of 12,431.76 feet, a central

*angle of 4º47’12” and a long chord which bears

*S33º13’17”W a distance of 1,038.30 feet;

thence S35º36’53”W a distance of 2,568.66 feet

to the South line of the aforesaid Section 5;

thence N89º29’19”W along said South line a

distance of 550.04 feet to the Point of Beginning.

Exhibit E Page 18

Coal Supply Agreement

Ute Mountain Ute Tribe, Transportation ‘Haulroad’ Corridor

Township 31 North, Range 14 West, NMPM, approx. 116.95 acres

A tract of land which is more specifically

described as follows:

Beginning at a point on the East boundary of said

Range 14 West whence the Northwest Corner of

Section 18, T31N, R13W, NMPM bears

N00°55’17”E a distance of 853 feet;

thence S00°55’17”W a distance of 412.00 feet

along said range line;

thence S40°09’02”W a distance of 2,370.92 feet;

thence S37°44’32”W a distance of 185.50 feet;

thence S52°15’28”E a distance of 165.00 feet;

thence S37°44’32”W a distance of 500.00 feet;

thence N52°15’28”W a distance of 165.00 feet

thence S37°44’32”W a distance of 200.00 feet;

thence S52°15’28”E a distance of 75.00 feet;

thence S37°44’32”W a distance of 700 feet;

thence N52°15’28”W a distance of 75.00 feet;

thence S37°44’32”W a distance of 1,564.50 feet

to a point of tangency with a curve to the left;

thence 1,002.04 feet along the arc of said curve

which has radius of 40,798.56 feet, a central

angle of 01°24’26” and a long chord which bears

S37°02’19”W a distance of 1,002.01 feet;

thence S36°20’06”W a distance of 2,806.94 feet

to a point of tangency with a curve to the right;

thence 1,005.56 feet along the arc of said curve

which has a radius of 9,736.73 feet, a central

angle of 05°55’02” and a long chord which bears

S39°17’37”W a distance of 1,005.11 feet;

thence S42°15’08”W a distance of 1,425.81 feet;

thence S47°44’52”E a distance of 25.00 feet;

thence S42°15’08”W a distance of 500.00 feet;

thence N47°44’52”W a distance of 25.00 feet;

thence S42°15’08”W a distance of 924.19 feet;

thence S47°44’52”E a distance of 165.00 feet;

thence S42°15’08”W a distance of 650.00 feet;

thence N47°44’52”W a distance of 165.00 feet;

thence S42°15’08”W a distance of 2,655.18 feet

to a point of tangency with a curve to the right;

thence 2,192.00 feet along the arc of said curve

Exhibit E Page 19

Coal Supply Agreement

Ute Mountain Ute Tribe (Con’t.)

which has a radius of 5,206.62 feet, a central

angle of 24°07’18” and a long chord which bears

S54°18’47”W a distance of 2,175.85 feet;

thence S23°37’47”E a distance of 25.00 feet to a

non-tangent point of intersection with a curve

which is concave to the Northwest;

thence 291.66 feet along the arc of said curve

which has a radius of 5,231.62, a central angle

of 3°11’39” and a long chord which bears

S67°58’16”W a distance of 291.62 feet;

thence S69°34’05”W a distance of 218.11 feet;

thence N20°25’55”W a distance of 25.00 feet;

thence S69°34’05”W a distance of 1,168.74 feet;

thence S68°07’53”W a distance of 1,579.63 feet;

thence S21°52’07”E a distance of 25.00 feet;

thence S68°07’53”W a distance of 250.00 feet;

thence N21°52’07”W a distance of 25.00 feet;

thence S68°07’53”W a distance of 3,738.70 feet

to a point of tangency with a curve to the right;

thence 855.55 feet along the arc of said curve

which has a radius of 4,973.25 feet, a central

angle of 09°51’24” and a long chord which bears

S73°03’35”W a distance of 854.50 feet;

thence S12°00’43”E a distance of 165.00 feet to

a non-tangent point of intersection with a curve

which is concave to the Northwest;

thence 672.27 feet along the arc of said curve

which has a radius of 5,138.25 feet; a central

angle 07°29’47” and a long chord which bears

S81°44’10”W a distance of 671.79 feet;

thence N04°30’56”W a distance of 165.00 feet

a non-tangent point of intersection with a curve

which is concave to the northwest;

thence 100.01 feet along the arc of said curve

which has a radius of 4,973.25 feet, a central

angle of 01°09’08” and a long chord which

bears S86°03’39”W a distance of 100.01 feet;

Exhibit E Page 20

Coal Supply Agreement

Ute Mountain Ute Tribe (Con’t.)

thence S86°38’12”W a distance of 318.57 feet

to a point of tangency with a curve to the left;

thence 1,859.59 feet along the arc of said curve

which has a radius of 2,491.00 feet, a central

angle of 42°46’21” and a long chord which

bears S65°15’01”W a distance of 1,816.70 feet;

thence S43°51’50”W a distance of 1,800.42 feet;

thence S46°08’10”E a distance of 25.00 feet;

thence S43°51’50”W a distance of 500.00 feet;

thence N46°08’10”W a distance of 25.00 feet;

thence S43°51’50”W a distance of 111.93 feet

to a point of intersection with the south

boundary of said Township 31 North;

thence N89°45’09”W a distance of 172.66 feet

along said South boundary;

thence N43°51’50”E a distance of 231.04 feet;

thence N46°08’10”W a distance of 25.00 feet;

thence N43°51’50”E a distance of 500.00 feet;

thence S46°08’10”E a distance of 25.00 feet;

thence N43°51’50”E a distance of 1,800.42 feet

to a point of tangency with a curve to the right;

thence 1,952.90 feet along the arc of said curve

which has a radius of 2,616.00 feet, a central

angle of 42°46’21” and a long chord which

bears N65°15’01”E a distance of 1,907.87 feet;

thence N86°38’12”E a distance of 318.57 feet

to a point of tangency with a curve to the left;

thence 1,565.88 feet along the arc of said curve

which has a radius of 4,848.25 feet, a central

angle of 18°30’19” and a long chord which

bears N77°23’02”E a distance of 1,559.08 feet;

thence N68°07’53”E a distance of 3,708.70 feet;

thence N21°52’07”W a distance of 100.00 feet;

thence N68°07’53”E a distance of 250.00 feet;

thence S21°52’07”E a distance of 100.00 feet;

thence N68°07’53”E a distance of 1,611.10 feet;

thence N20°25’55”W a distance of 165.00 feet;

Exhibit E Page 21

Coal Supply Agreement

Ute Mountain Ute Tribe (Con’t.)

thence N69°34’05”E a distance of 500.00 feet;

thence S20°25’55”E a distance of 165.00 feet;

thence N69°34’05”E a distance of 670.47 feet;

thence N20°25’55”W a distance of 25.00 feet;

thence N69°34’05”E a distance of 218.11 feet

to a point of tangency with a curve to the left;

thence 281.90 feet along the arc of said curve

which has a radius of 5,056.62 feet, a central

angle of 3°11’39” and a long chord which bears

N67°58’16”E a distance of 281.86 feet;

thence S23°37’47”E a distance of 25.00 feet to a non-tangent point of intersection with a curve which is concave to the northwest;

thence 2,139.38 feet along the arc of said curve

which has a radius of 5,081.62 feet, a central

angle of 24°07’18” and a long chord which

bears N54°18’47”E a distance of 2,123.61 feet;

thence N42°15’08”E a distance of 4,229.37 feet;

thence N47°44’52”W a distance of 25.00 feet;

thence N42°15’08”E a distance of 500.00 feet;

thence S47°44’52”E a distance of 25.00 feet;

thence N42°15’08”E a distance of 1,425.81 feet

to a point of tangency with a curve to the left;

thence 992.66 feet along the arc of said curve

which has a radius of 9,611.78 feet, a central

angle of 05°55’02” and a long chord which

bears N39°17’37”E a distance of 992.22 feet;

thence N36°20’06”E a distance of 575.02 feet;

thence N53°39’54”W a distance of 165.00 feet;

thence N36°20’06”E a distance of 650.00 feet;

thence S53°39’54”E a distance of 165.00 feet;

thence N36°20’06”E a distance of 1,581.92 feet

to a point of tangency with a curve to the right;

thence 252.56 feet along the arc of said curve

which has a radius of 40,923.56 feet, a central

angle of 00°21’13” and a long chord which

bears N36°30’43”E a distance of 252.57 feet;

thence N53°18’41”W a distance of 25.00 feet

to a non-tangent point of intersection with a

Exhibit E Page 22

Coal Supply Agreement

Ute Mountain Ute Tribe (Con’t.)

curve which is concave to the southeast;

thence 500.28 feet along the arc of said curve

which has a radius of 40,948.56 feet, a central

angle of 00°42’00” and a long chord which

bears N37°02’19”E a distance of 500.28 feet;

thence S52°36’41”E a distance of 25.00 feet

to a non-tangent point of intersection with a

curve which is concave to the southeast;

thence 252.56 feet along the arc of said curve

which has a radius of 40,923.56 feet, a central

angle of 00°21’13” and a long chord which

bears N37°33’56”E a distance of 252.57 feet;

thence N37°44’32”E a distance of 1,464.50 feet;

thence N52°15’28”W a distance of 50.00 feet;

thence N37°44’32”E a distance of 650.00 feet;

thence S52°15’28”E a distance of 50.00 feet;

thence N37°44’32”E a distance of 450.00 feet;

thence N52°15’28”W a distance of 80.00 feet;

thence N37°44’32”E a distance of 400.00 feet;

thence S52°15’28”E a distance of 80.00 feet;

thence N37°44’32”E a distance of 185.50 feet;

thence N33°05’30”E a distance of 1,541.72 feet;

thence N42°47’37”E a distance of 1,166.53 feet

to the Point of Beginning.

Ute Mountain Ute Tribe, Borrow Area No. 6

Township 31 North, Range 14 West, NMPM, approx. 8.02 acres

Section 33: Pt. SW¼, which is more particularly

described as follows:

Beginning at a point which bears S75°25’58”E a distance of

522.87 feet from the West Quarter Corner of

said Section 33, said point of beginning being a

point on the Southerly right-of-way line of the

San Juan Coal Company Haul Road;

thence N85°44’05”E a distance of 78.12 feet (chord

distance) along said right-of-way;

thence N86°38’12”E a distance of 318.57 feet along said

right-of-way;

thence N86°03’39”E a distance of 100.01 feet (chord

distance) along said right-of-way;

thence S04°30’56”E a distance of 165.00 feet;

thence S03°21’48”E a distance of 535.00 feet;

thence S86°38’12”W a distance of 500.00 feet;

thence N03°21’48”W a distance of 697.74 feet to the

Exhibit E Page 23

Coal Supply Agreement

Point of Beginning.

Ute Mountain Ute Tribe, Borrow Area No. 7

Township 31 North, Range 14 West, NMPM, approx. 9.64 acres

Section 26: Pt. SW¼

Section 27: Pt. SE¼, said tracts being more

particularly described as follows:

Beginning at a point which bears S15°28’16”W a distance of 208.17 feet from the East

Quarter Corner of said Section 27;

thence S47°44’52”E a distance of 700.00 feet to a point

on the Westerly right-of-way line of the

San Juan Coal Company Haul Road;

thence S42°15’08”W a distance of 400.01 (chord distance) feet along said

right-of-way;

thence S43°21’33”W a distance of 200.04 (chord distance) feet along said

right-of-way;

thence N47°44’52”W a distance of 696.14 feet;

thence N42°15’08”E a distance of 600.00 feet to the

Point of Beginning.

Ute Mountain Ute Tribe, Borrow Area No. 8

Township 31 North, Range 14 West, NMPM, approx. 10.33 acres

Section 26: N½, more particularly described

as follows:

Beginning at a point which bears S08°01’26”E a distance of 257.69

feet from the North Quarter Corner of said

Section 26;

thence S47°44’52”E a distance of 450.00 feet to a point

on the Westerly right-of-way line of the

San Juan Coal Company Haul Road;

thence S42°15’08”W a distance of 1,000.00 feet along

said right-of-way;

thence N47°44’52”W a distance of 450.00 feet;

thence N42°15’08”E a distance of 1,000.00 feet to the

Point of Beginning.

Ute Mountain Ute Tribe, Drainage Control Right-of-Way

Township 31 North, Range 14 West, NMPM, approx. 31.27 acres

A tract of land which is more specifically

described as follows:

Using the bearing of due

North between the West Quarter Corner and

the Northwest corner of Section 33, T31N, R14W,

NMPM, as the basis of bearing; and beginning

Exhibit E Page 24

Coal Supply Agreement

at a point from which the West Quarter Corner

of said Section 33 bears N53°01’21”W a distance

of 1,318.25 feet;

thence S86°38’12”W a distance of 500.00 feet;

thence N03°21’48”W a distance of 697.74 feet to a non-tangent point of intersection with a curve to the left;

thence 100.14 feet along the arc of said curve

which has a radius of 2,490.98 feet, a central angle

of 2°18’12” and a long chord which bears

S83°41’27”W a distance of 100.13 feet;

thence S03°21’48”E a distance of 789.84 feet;

thence N86°38’12”E a distance of 708.14 feet;

thence N03°21’48”W a distance of 535.00 feet

to a non-tangent point of intersection with a

curve which is concave to the northwest;

Ute Mountain Ute Tribe, Drainage Control Right-of-Way (Con’t.)

thence 685.36 feet along the arc of said curve

which has a radius of 5,238.25 feet, a central angle

of 07°29’47” and a long chord which bears

N80°34’24”E a distance of 684.86 feet;

thence N13°09’50”W a distance of 165.40 feet

to a non-tangent point of intersection with a

curve which is concave to the northwest;

thence 769.76 feet along the arc of said curve

which has a radius of 5,073.25 feet, a central

angle of 08°41’37” and a long chord which

bears N72°28’42”E a distance of 769.04 feet;

thence N68°07’53”E a distance of 3,638.70 feet;

thence S21°52’07”E a distance of 175.00 feet;

thence N68°07’53”E a distance of 450.00 feet;

thence N21°52’07”W a distance of 175.00 feet;

thence N68°07’53”E a distance of 1,484.96 feet;

thence N69°34’30”E a distance of 1,053.97 feet;

thence S20°25’30”E a distance of 25.00 feet;

thence N69°34’30”E a distance of 325.00 feet to

a point of tangency with a curve

which is concave to the northwest;

thence 399.15 feet along the arc of said curve

which has a radius of 5,331.62 feet, a central

angle of 04°17’22” and a long chord which bears

N67°25’24”E a distance of 399.06 feet;

thence N24°43’17”W a distance of 25.00 feet to

a non-tangent point of intersection with a curve

which is concave to the northwest;

thence 1,080.36 feet along the arc of said curve

Exhibit E Page 25

Coal Supply Agreement

which has a radius of 5,306.62 feet, a central

angle of 11°39’53” and a long chord which

bears N59°26’47”E a distance of 1,078.88 feet;

thence N36°23’10”W a distance of 100.36 feet

to a non-tangent point of intersection with a

curve which is concave to the northwest;

thence 1,159.54 feet along the arc of said curve

which has a radius of 5,206.62 feet, a central

angle of 12°45’36” and a long chord which

bears S59°59’38”W a distance of 1,157.14 feet;

Ute Mountain Ute Tribe, Drainage Control Right-of-Way (Con’t.)

thence S23°37’47”E a distance of 25.00 feet to

a non-tangent point of intersection with a curve

which is concave to the northwest;

thence 291.66 feet along the arc of said curve

which has a radius of 5,231.62 feet, a central

angle of 03°11’39” and a long chord which

bears S67°58’16”W a distance of 291.62 feet;

thence S69°34’05”W a distance of 218.11 feet;

thence N20°25’55”W a distance of 25.00 feet;

thence S69°34’05”W a distance of 1,168.74 feet;

thence S68°07’53”W a distance of 1,579.63 feet;

thence S21°52’07”E a distance of 25.00 feet;

thence S68°07’53”W a distance of 250.00 feet;

thence N21°52’07”W a distance of 25.00 feet;

thence S68°07’53”W a distance of 3,738.70 feet

to a point of tangency with a curve to the right;

thence 855.55 feet along the arc of said curve

which has a radius of 4,973.25 feet, a central

angle of 09°51’24” and a long chord which

bears S73°03’35”W a distance of 854.50 feet;

thence S12°00’43”E a distance of 165.00 feet

to a non-tangent point of intersection with a

curve which is concave to the northwest;

thence 672.27 feet along the arc of said curve

which has a radius of 5,138.25 feet, a central

angle of 07°29’47” and a long chord which

bears S81°44’10”W a distance of 671.79 feet;

thence S03°22’21”E a distance of 535.00 feet to the Point of Beginning.

Exhibit E Page 26

Coal Supply Agreement

Foutz, Joel W., et al (now Wagon Rod Ranch)

(Transportation ‘Haulroad’ Corridor)

Township 30 North, Range 14 West, NMPM, approx. 56.34 acres

Section 5: Pt. of the NW¼SW¼, NW¼

Section 6: Pt. of the SE¼, SE¼NE¼

Section 7: Pt. of the N½. Said easement shall be

225 feet wide, lying 112.5 feet on each side of

a center line more particularly described as follows:

Beginning at a point from which the

southwest corner of Section 7 bears

S05º18’19”W a distance of 2,641.32 feet;

thence from said Point of Beginning

N43º51’58”E a distance of 10,908.22 feet, more or less,

to the North line of Section 5.

Mangis, Robert A., et al

(Transportation ‘Haulroad’ Corridor)

Township 30 North, Range 15 West, NMPM, approx. 7.27 acres

Section 12: Pt. SW¼SE¼ more particularly

described as follows:

Beginning at a point on

the West line of the E½SE¼ of said Section

12 whence the Southeast Corner of said

Section 12 bears S57º20’00”E a distance of

1,563.64 feet;

thence S43º51’51”W a distance of 872.48 feet

to a point of tangency with a curve to the right;

thence 294.29 ft, more or less, along the arc of

said curve which has a radius of 2977.29 feet, a

central angle of 05º39’48” and a long chord

which bears S46º41’44”W a distance of 294.17

feet to the South line of said Section 12;

thence N89º38’49”W along said South line of

Section 12, a distance of 365.47 feet to a non-

tangent point of intersection with a curve which

is concave to the Northwest;

thence 549.07 feet along the arc of said curve which

has a radius of 2,752.29 feet, a central angle of

11º25’49” and a long chord which bears

N49º34’45”E a distance of 548.16 feet;

thence N43º51’50”E a distance of 1,106.59 feet,

more or less, to the West line of the E½SE¼ of said

Section 12;

thence S00º00’00”E along said West line of the

E½SE¼ of said Section 12, a distance of 324.70 feet,

more or less, to the Point of Beginning.

Exhibit E Page 27

Coal Supply Agreement

Wagon Rod Ranch Limited Liability Co.

(Transportation ‘Haulroad’ Corridor)

Township 30 North, Range 15 West, NMPM, approx. 11.74acres

Section 14: Pt. E½NE¼, NE¼SE¼

more particularly described as follows:

Beginning at a point on the East line of said Section 14

from which the Northeast corner of said

Section 14 bears N00º25’30”E a distance of

994.58 feet;

thence S00º25’30”W a distance of 266.19 feet

to a non-tangent point of intersection with a

curve which is concave to the southeast;

thence 1,060.43 feet along the arc of said curve

which has a radius of 2,179.33 feet, a central

angle of 27º52’46” and a long chord which

bears S42º21’39”W a distance of 1,050.00 feet;

thence S28º25’16”W a distance of 839.51 feet

to a point of tangency with a curve to the right;

thence 435.70 feet, more or less, along the

arc of said curve which has a radius of 5,842.08

feet, a central angle of 04º16’23” and a long

chord which bears S30º33’28”W a distance of

435.60 feet, to the West line of the E½SE¼ of

said Section 14;

thence N00º24’38”E along the West line of the

E½SE¼ of said Section 14, a distance of 444.86

feet to a non-tangent point of intersection with a

curve which is concave to the northwest;

thence 42.55 feet along the arc of said curve which

has a radius of 5,617.08 feet, a central angle of

00º26’02” and a long chord which bears

N28º38’18”E a distance of 42.54 feet;

thence N28º25’17”E a distance of 839.51 feet to a

point of tangency with a curve to the right;

thence 1,319.34 feet, more or less, along the arc

of said curve which has a radius of 2,404.33 feet, a

central angle of 31º26’25” and a long chord which

bears N44º08’29”E a distance of 1,302.85 ft, to the

Point of Beginning.

Exhibit E Page 28

Coal Supply Agreement

NM 55331 Right-of-Way Parcel – X (maybe #5 or #9)

Note: This description is approximate and is based on the adjacent ROW parcels #10 and #11 and aerial images of this area. The available documents lack any description for this segment of the La Plata Haul Road.

Township 30 North, Range 15 West, NMPM, approx. 24.29 acres

Section 21: Pt. NE1/4 which is more specifically described as follows:

Beginning at a point from which the Northeast corner of said

Section 21 bears N00º09’05”E

a distance of 1,002.94 feet;

thence S87º23’54”W a distance of 1,561.13 feet

to a point of tangency with a curve to the left;

thence 187.44 feet along the arc of said curve

which has a radius of 2,109.86 feet, a central

angle of 05º05’43” and a long chord which

bears S84º46’41”W a distance of 187.38 feet;

thence S82º18’16”W a distance of 896.00 feet;

thence S00º10’14”W a distance of 403.80 feet;

thence N82º18’16”E a distance of 951.96 feet;

to a point of tangency with a curve to the right;

thence 152.06 feet along the arc of said curve

which has a radius of 1,709.86 feet, a central

angle of 05º05’43” and a long chord which

bears N84º46’41”E a distance of 151.68 feet;

thence N87º23’54”E a distance of 1,541.35 feet;

thence N00º09’05”E a distance of 400.45 feet;

to the Point of Beginning.

A Parcel from PNM/TEP to SJCC - to widen an existing road to the south of SJCC’s gate house. Township 30 North, Range 15 West, NMPM, approx. 0.422 acres

Section 20, part of the southeast quarter

More particularly described as follows:

commencing at the Point of Beginning from

which the West ¼ corner of Section 28, T30N,

R15W, NMPM, bears S23º12’05”E, 4,179.02 feet;

thence N67º51’36”W, a distance of 372.42 feet;

thence S63º16’35”E, a distance of 371.18 feet;

thence S63º29’36”E, a distance of 151.55 feet;

thence S50º36’27”E, a distance of 288.31 feet;

thence N00º06’28”W, a distance of 38.86 feet;

thence N50º38’05”W, a distance of 266.86 feet;

thence N63º31’14”W, a distance of 154.86 feet to the Point of Beginning.

Exhibit E Page 29

Coal Supply Agreement

A Parcel from PNM/TEP to SJCC an easement for a water pipeline running into a process pond at San Juan Generating Station

Township 30 North, Range 15 West, NMPM, approx. 0.111 acres

Section 20, part of the southeast quarter

More particularly described as follows:

An easement 20 feet wide, being 10 feet on

each side of the following described centerline:

commencing at the Point of Beginning from which

the SE corner of said Section 20

bears S31º08’51”E, 2,040.85 feet;

thence N24º17’46”W, a distance of 240.54 feet.

Exhibit E Page 30

Coal Supply Agreement

EXHIBIT F—SJCC INSURANCE REQUIREMENTS

SJCC shall, commencing with the Effective Date, maintain or cause to be maintained the insurance coverages and provisions set forth below. For purposes of this Exhibit F only, the term “Utilities” shall mean Utility, Tucson Electric Power, the City of Farmington, New Mexico, the Incorporated County of Los Alamos, New Mexico, Utah Associated Municipal Power Systems, Tri-State Generation and Transmission Association, Inc., City of Anaheim, Southern California Public Power Authority, M-S-R Public Power Agency and PNMR Development and Management Corporation, along with their respective affiliates, subsidiaries, directors, officers, managers, representatives, agents and employees. For purposes of this Exhibit F, Public Service Company of New Mexico shall be deemed the “Operator”.

(1)

To the extent permitted by law, SJCC waives on behalf of itself and its insurer all rights of recovery by subrogation or otherwise, or to assert claims for any losses, damages, liabilities, and expenses, including but not limited to attorney’s fees, against Utilities for damages. The following policies shall include an endorsement acknowledging such waiver of subrogation: Workers Compensation, Commercial General Liability, Commercial Auto Liability, Umbrella/Excess Liability, and Pollution Liability.


(2)	Each insurance company listed on the SJCC’s certificate of insurance shall be rated by A.M. Best Company as having a financial strength rating of “A- “ or better and a financial size category of “VIII” or greater or otherwise be satisfactory to Operator.


(3)	All policies other than pollution liability policies must be written on an occurrence basis and maintained without interruption from the date of the commencement of services under the Agreement. Required minimum limits can be satisfied with a combination of a primary and either single or combination of excess policies.

(4)

SJCC shall furnish to the Operator sixty (30) days prior to the Effective Date and thereafter within three (3) days of the renewal of any policy required herein a certificate of liability insurance on ACORD 25 or a substitute equivalent form approved by the Operator (Liability Certificate) and a certificate of property insurance (Property Certificate) on ACORD 28 or a substitute equivalent form approved by the Operator (Property Certificate).. The Liability Certificate and Property Certificate shall include as evidence of insurance the following for each and every policy providing, Commercial Automobile Liability, Workers’ Compensation, Commercial General Liability, Umbrella/Excess Liability, Pollution Liability, and Property coverages required herein: (i) insurance company name, (ii) policy number, (iii) policy period, (iv) per occurrence and aggregate limits, (v) deductibles or self-insured retentions, and (vi) attached copies of all applicable additional insured and waiver of subrogation endorsements.

(5)

SJCC agrees to send to Operator, by certified mail, at least thirty (30) days advance written notice of cancellation, non-renewal, or material change with respect to any of the policies required herein. SJCC shall also endorse its policies to require the insurer to provide advance written notice of cancellation to Operator. If any of the above insurance policies are canceled prior to expiration, SJCC agrees to immediately replace the insurance without lapse of coverage.

Exhibit F Page 1

Coal Supply Agreement


(6)	A lack of insurance coverage does not reduce or limit SJCC’s obligation to indemnify Operator as set forth in the Agreement.


(7)	Material Breach. Should any of the policies required to be maintained by SJCC become unavailable or be canceled for any reason during the period of this Agreement, SJCC shall immediately procure replacement coverage. The failure of SJCC to procure such replacement coverage (so as to provide continuous coverage) shall constitute a material breach hereunder.

(8)

SJCC shall provide to Operator on an annual basis a schedule of insurance outlining: coverage type, insureds, policy number, policy term, insurer, limits, self-insured retention or deductible, specific exclusions, and premium. In addition, policies of insurance shall be provided upon written request from Operator. Upon Operator’s written request, SJCC shall provide to Operator copies of claim submission information and supporting documents; correspondence with insurers; proposed claim settlement offers; and copies of correspondence with defense counsel for significant claims.

(9)

In the event of a material change to be made to a policy, SJCC shall give at least 180 days’ notice in writing prior to the next incepting coverage term of the respective insurance policy a description of the proposed change to Operator. SJCC shall provide additional supporting documentation for proposed change upon written request from Operator. No material changes are to be made to a policy without Operator’s concurrence. Except for minor changes, which shall be outlined in the annual schedule of insurance.

All coverages required for all work performed under the Agreement. All coverages shall provide coverage for acts of domestic and foreign terrorism meeting the requirements for being certified acts of terrorism by the Terrorism Risk Insurance Act as amended by the Terrorism Risk Insurance Program Reauthorization Act of 2015.

(1)

Commercial General Liability Insurance , or the equivalent, with a minimum limit of One Million U.S. Dollars (USD $1,000,000) combined single limit per occurrence for bodily injury and property damage, One Million U.S. Dollars (USD $1,000,000) each organization or person for personal and advertising injury, Two Million U.S. Dollars (USD $2,000,000) general aggregate, and Two Million U.S. Dollars (USD $2,000,000) products and completed operations aggregate. Such coverage shall also not include any exclusion for mining limitations. Aggregate limits shall reinstate annually. SJCC’s policy shall (i) provide severability of interests or cross liability provisions permitting one insured to bring a claim against another insured, (ii) shall be primary and non-contributory to any other insurance available to Utilities, and (iii) shall be endorsed to add as additional insured Utilities (but limited only to the extent required, if applicable, by NMSA 1978 § 56-7-1, as amended).

(2)

Commercial Automobile Liability Insurance covering the ownership, maintenance, and use of any vehicle, trailers or attached equipment in performance of the Work, whether such vehicle is owned, hired, or non-owned. SJCC shall maintain insurance with a combined single limit for bodily injury and property damage of not less than the equivalent of Five Million U.S. Dollars (USD $5,000,000) each accident. SJCC’s policy shall provide coverage in reference to the MCS-90 liability provision. SJCC’s policy (i) shall be primary and

Exhibit F Page 2

Coal Supply Agreement

non-contributory to any other insurance available to Utilities, and (ii) shall be endorsed to add as an additional insured Utilities (but limited only to the extent required, if applicable, by NMSA 1978 § 56-7-1, as amended).

(3)

Workers’ Compensation Insurance covering statutory benefits in each state where the parties contemplate the performance of services under this agreement. The workers’ compensation coverage part shall include “other states” insurance, to provide coverage for all states not named on the declarations page of the insurance policy, except for the monopolistic states. Such insurance shall include the Employer’s Liability coverage part, including stop gap coverage for the monopolistic states, with limits of not less than One Million U.S. Dollars (USD $1,000,000) each accident for bodily injury by accident and One Million U.S. Dollars (USD $1,000,000) each employee and policy limit for bodily injury by disease.

(4)

Umbrella/Excess Liability Insurance providing coverage in excess of the Commercial General Liability, Commercial Automobile Liability, and Employer’s Liability insurance described above on an occurrence basis with limits of at least One Hundred Million U.S. Dollars (USD $100,000,000) per occurrence. Such insurance shall (i) be written in the following form or with a form that provides coverage that is at least as broad as the underlying insurance policies, (ii) can satisfy the required minimum limits either through a single umbrella liability policy or a combination of umbrella liability and excess liability policies, (iii) be primary and non-contributory to any other insurance available to Utilities, and (iv) shall be endorsed to add as an additional insured Utilities (but limited only to the extent required, if applicable, by NMSA 1978 § 56-7-1, as amended).

(5)

Pollution Liability Insurance covering SJCC and its subcontractors from claims brought by third parties for bodily injury, property damage and financial loss, including but not limited to cleanup costs, arising from Pollution Conditions caused by SJCC’s operations with limits in the amount of not less than the equivalent of Twenty-Five Million U.S. Dollars (USD $25,000,000) per occurrence and Twenty-Five Million U.S. Dollars (USD $25,000,000) general aggregate. Such insurance shall define Pollution Conditions at a minimum, whether sudden or gradual, as the discharge, dispersal, release, or escape of any solid, liquid, gaseous, or thermal irritant or contaminant, including smoke, vapors, soot, fumes, acids, alkalis, toxic chemicals, medical waste and waste materials into or upon land, or any structure on land, the atmosphere or any watercourse or body of water, including groundwater, provided such conditions are not naturally present in the environment in the concentration or amounts discovered and shall not include an exclusion for selenium. In the event of a pollution loss, such coverage shall also include coverage for fines and penalties and for transportation and disposal. Policies shall be endorsed to add Utilities as an additional insured (but limited only to the extent required, if applicable, by NMSA 1978 § 56-7-1, as amended).


(6)	Commercial Property Insurance covering the above ground and underground equipment, buildings, any personal property, stock or inventory therein in an amount equal to the full replacement value thereof. Policies shall include coverage for:


(i)	such perils as are commonly included in an “all risk” form with no exclusions for wind and hail, vandalism and malicious mischief, and endorsed to include the perils of earthquake and flood;


(ii)	an “agreed amount” endorsement waiving any coinsurance requirement;

Exhibit F Page 3

Coal Supply Agreement


(iii)	an Ordinance or Law endorsement including coverage for (i) loss to the undamaged portion of the equipment or building at full replacement cost value; and (ii) required demolition of undamaged portions of the equipment and building, and (iii) increased cost of construction with a combined single limit of not less than 25% of the full replacement cost value;


(iv)	such other risks at terms and limits that include but not necessarily limited to:


(1)	Accounts Receivable


(2)	Civil Authority


(3)	Consequential Damage


(4)	Contingent Business Interruption


(5)	Course of Construction


(6)	Debris Removal


(7)	Decontamination Expense


(8)	EDP Data and Media


(9)	EDP Systems


(10)	Expediting Expenses


(11)	Ingress/Egress


(12)	Mold and Fungus Cleanup Expenses


(13)	Personal Property of Employees


(14)	Pollution Cleanup


(15)	Service Interruption


(16)	Property In Transit


(17)	Valuable Papers and Records


(v)	Utilities shall be named as loss payee with respect to all insurance covering damage to or loss of any above ground or underground equipment, building, personal property, stock or inventory. Any deductibles under said Property Insurance coverages shall be the responsibility of the SJCC.


(vi)	Business Interruption and Extra Expense resulting from loss or damage from the hazards specified above, which prevents normal operations from continuing.


(vii)	Extended Period of Indemnity insurance providing coverage for continued loss of income after the date of restoration for a period of not less than twelve (12) months after business operations have resumed.

“Full replacement value” as used herein, means the cost of repairing, replacing, or reinstating, including demolishing, any item of property, with materials of like kind and quality in compliance with, (and without, an exclusion pertaining to application of), any law or building ordinance regulating repair or construction at the time of loss and without deduction for physical, accounting, or any other depreciation, in an amount sufficient to meet the requirements of any applicable co-insurance clause.

(7)

Equipment Breakdown Insurance using a comprehensive machinery coverage form covering sudden and accidental breakdown of objects whether above ground or below ground, which shall be defined to include any fired or unfired vessel normally subject to vacuum or internal pressure, any refrigerating or air conditioning system with piping and accessory equipment, and any mechanical or electrical machine or apparatus which generates, controls, transmits, transforms, or utilizes mechanical or electrical power. Property damage shall be covered in an amount equal to 100% of the actual replacement value of such items, and business income coverage shall provide full recovery of the net profits and continuing expenses on an actual loss sustained basis.

Exhibit F Page 4

Coal Supply Agreement

(8)

In the event there is work to be performed that includes demolition, construction or expansion of above ground or underground equipment, buildings, or personal property whose value exceeds the sublimits for the in course of construction coverage on the commercial property program, builders risk or course of construction insurance shall be put in place unless agreed to otherwise by Operator in writing. Builders Risk or Course of Construction Insurance shall provide coverage against loss or damage to any improvements to real property whether above ground or below ground during any period of construction at or on the property or renovation or alteration of the improvements to the extent that coverage is either not provided under the Commercial Property Insurance set forth above or the sublimit for such coverage under the Commercial Property Insurance is less than the completed value. Such Builders Risk or Course of Construction insurance shall be on an “all risks” basis that does not exclude the perils of flood and earthquake. The completed value form shall specify the estimated completed value of the Project at the end of construction. The Builder’s Risk Policy shall be endorsed to include (a) replacement cost coverage; (b) delayed completion coverage; (c) property in transit coverage for materials and equipment to be incorporated into the real property above ground or underground; (d) permission for partial occupancy or use of the premises; (e) ordinance or law coverage, including (i) coverage for loss to the undamaged portion of the above ground or below ground real property, (ii) demolition cost coverage, (iii) increased cost of construction; and (f) a standard mortgage clause providing for at least ten (10) days’ advance written notice of cancellation to the Lender. The delayed completion coverage endorsement shall provide on an actual loss sustained basis indemnification for scheduled soft costs, loss of rental income, and loss of gross earnings arising from any delay in the completion of the insured project due to direct physical loss or damage to the insured structures or materials.

(9)

Crime Insurance with employee dishonesty coverage to be maintained throughout the term of this Agreement with a minimum limit of (Five Hundred Thousand Dollars $500,000) each occurrence. Such policy shall (a) provide coverage against the dishonest and fraudulent acts of SJCC’s employees, officers, as well as any temporary employees, leased employees and independent contractors working on behalf of SJCC; (b) be issued on a discovery form providing coverage for all losses discovered during the policy period without regard to date of occurrence, or alternatively on a loss sustained form providing coverage for losses occurring during the current policy period and at least one preceding policy period; (c) shall be endorsed to include a third party client endorsement covering money, securities and other property owned by, held by or the legal responsibility of Utilities; and (d) name Utilities as a loss payee as their interests may appear through a loss payable endorsement


(10)	Fiduciary Liability Insurance covering any errors and omissions committed by the officers, employees, including temporary employees, leased employees and independent contractors working on behalf of the SJCC in the administration of employee benefit programs as imposed by the Employe e Retirement Income Security Act with a minimum limit of One Million Dollars ($1,000,000) each occurrence.

Exhibit F Page 5

Coal Supply Agreement

EXHIBIT G— FIRST YEAR APPROVED ANNUAL OPERATING PLAN

Notwithstanding the effectiveness of the Agreement in accordance with Section 2.3, the Parties shall, promptly upon execution of the Agreement, jointly develop the Approved Annual Operating Plan for the 2016 Contract Year. Such Approved Annual Operating Plan for the 2016 Contract Year shall be completed before November 1, 2015 and shall upon completion be deemed incorporated herein as Exhibit G.

Coal Supply Agreement

EXHIBIT H—COAL QUALITY MEASURES

The following shall collectively constitute the “ Coal Quality Measures .” To the extent any equipment specified in this Exhibit H or otherwise required to perform the tasks below are not already installed, SJCC shall install such equipment in accordance with time frame specified herein and immediately commence operation in accordance with this Exhibit H . SJCC will exercise commercially reasonable good-faith efforts to implement such Coal Quality Measures earlier than the dates specified herein.

In-Mine Measures


1.	SJCC shall perform detailed in-mine mapping, including of splits, channels, seam thickness changes, etc. To be implemented no later than April 1, 2016.


2.	SJCC shall obtain channel samples for every pillar on development of gate entries with analysis (short prox) conducted and mapped, which may also require roof and floor auger samples. To be implemented no later than April 1, 2016.


3.	SJCC shall conduct daily face profiles along the longwall face at 10 shield intervals and in each face of the development section(s) and provide calculated ash forecast. To be implemented no later than April 1, 2016.


4.	SJCC shall prepare a comprehensive longwall report as new panel is developed and prior to initiation of longwall retreat. To be implemented no later than April 1, 2016.

Construction Waste Material


1.	In order to handle waste material, SJCC shall prepare the ROM pile to receive waste material separate from “clean” ROM coal.


2.	SJCC shall develop rock rooms and store material from section construction and store instead of shipping outside; provided that SJCC shall not be obligated to perform such actions if prohibited from doing so by the Mine Safety and Health Administration. To be installed and operational no later than April 1, 2016.


3.	SJCC shall install a flop gate on the ROM belt. As waste material is created, SJCC shall flop the gate and segregate waste material from the coal pile. To be installed and operational no later than April 1, 2016.

ROM In-Line Analyzer .


1.	SJCC shall install an additional stacking tube and cross conveyor at the mine delivery pile and shall use such stacking tube to segregate the various ROM qualities. To be installed and operational no later than October 16, 2016.


2.	SJCC shall install an in-line mineral ash analyzer and sampler on the ROM system to determine quality and determine final stockpile location. SJCC shall construct and install a scoreboard at the loading point of the ROM stockpile so that loader operators can determine destination of the truck being loaded. To be installed and operational no later than December 15, 2016.

Stockpile Designation


1.	SJCC shall designate three stockpiles for high sulfur, high ash and low ash. To be implemented no later than October 16, 2016.


2.	SJCC shall conduct updates of stockpile characterization on a routine basis (at least quarterly) to map quality of stockpiles. To be installed and operational no later than April 1, 2016.

Coal Supply Agreement

In-Line Analyzer / Sampler on Plant Delivery Belt

SJCC shall install an in–line mineral ash analyzer on the plant delivery belt with a sampling system. Additionally, SJCC shall place a scoreboard from the analyzer output by the reclaim on the main stockpile. Based on this information, SJCC shall make any adjustment needed on a small sample size to maximize quality and minimize variability. To be installed and operational no later than December 15, 2016.

Coal Supply Agreement

EXHIBIT I—TAXES AND ROYALTIES



Description	Current Rate
NM Underground Coal Severance Tax	$0.55/ton sold
NM Underground Coal Severance Surtax (New Agreements)	$0/ton sold
NM Resource Excise Tax	0.75%
NM Conservation Tax	0.19%
NM Underground Coal Royalty	8.00%
NM Gross Receipts Tax	6.5625%
Federal Underground Coal Black Lung Tax	$1.10/ton sold
Federal Underground Reclamation Act Levy	$0.12/ton sold
Federal Underground Coal Royalty	5.00%
Effective Surface Coal Royalty at La Plata Mine	6.625%

Exhibit I Page 1

Coal Supply Agreement

EXHIBIT J—PURCHASE PRICE ADJUSTMENT FACTORS (UTILITY EVENT OF DEFAULT)



Jan-16	1.224103	Apr-19	0.340333
Feb-16	1.198462	May-19	0.330977
Mar-16	1.173077	Jun-19	0.321620
Apr-16	1.147949	Jul-19	0.312264
May-16	1.123077	Aug-19	0.302907
Jun-16	1.098462	Sep-19	0.293551
Jul-16	1.074103	Oct-19	0.284194
Aug-16	1.050000	Nov-19	0.274838
Sep-16	1.026154	Dec-19	0.265481
Oct-16	1.002564	Jan-20	0.256125
Nov-16	0.979231	Feb-20	0.246768
Dec-16	0.956154	Mar-20	0.237412
Jan-17	0.933333	Apr-20	0.228055
Feb-17	0.910769	May-20	0.218699
Mar-17	0.888462	Jun-20	0.209343
Apr-17	0.866410	Jul-20	0.199986
May-17	0.844615	Aug-20	0.190630
Jun-17	0.823077	Sep-20	0.181273
Jul-17	0.801795	Oct-20	0.171917
Aug-17	0.780769	Nov-20	0.162560
Sep-17	0.760000	Dec-20	0.153204
Oct-17	0.739487	Jan-21	0.143847
Nov-17	0.719231	Feb-21	0.134491
Dec-17	0.699231	Mar-21	0.125134
Jan-18	0.480680	Apr-21	0.115778
Feb-18	0.471324	May-21	0.106421
Mar-18	0.461967	Jun-21	0.097065
Apr-18	0.452611	Jul-21	0.087708
May-18	0.443255	Aug-21	0.078352
Jun-18	0.433898	Sep-21	0.068995
Jul-18	0.424542	Oct-21	0.059639
Aug-18	0.415185	Nov-21	0.050282
Sep-18	0.405829	Dec-21	0.040926
Oct-18	0.396472	Jan-22	0.034105
Nov-18	0.387116	Feb-22	0.027284
Dec-18	0.377759	Mar-22	0.020463
Jan-19	0.368403	Apr-22	0.013642
Feb-19	0.359046	May-22	0.006821

Exhibit J Page 1

Coal Supply Agreement



Mar-19	0.349690	Jun-22	0.000000

Exhibit J Page 2

Coal Supply Agreement

EXHIBIT K—PURCHASE PRICE ADJUSTMENT FACTORS (ENVIRONMENTAL FORCE MAJEURE)



Jan-16	1.125564	Apr-19	0.340333
Feb-16	1.091554	May-19	0.330977
Mar-16	1.057968	Jun-19	0.321620
Apr-16	1.024807	Jul-19	0.312264
May-16	0.992071	Aug-19	0.302907
Jun-16	0.959760	Sep-19	0.293551
Jul-16	0.927874	Oct-19	0.284194
Aug-16	0.896413	Nov-19	0.274838
Sep-16	0.865377	Dec-19	0.265481
Oct-16	0.834766	Jan-20	0.256125
Nov-16	0.804580	Feb-20	0.246768
Dec-16	0.774819	Mar-20	0.237412
Jan-17	0.745483	Apr-20	0.228055
Feb-17	0.716572	May-20	0.218699
Mar-17	0.688086	Jun-20	0.209343
Apr-17	0.660025	Jul-20	0.199986
May-17	0.638776	Aug-20	0.190630
Jun-17	0.617528	Sep-20	0.181273
Jul-17	0.596279	Oct-20	0.171917
Aug-17	0.575031	Nov-20	0.162560
Sep-17	0.553782	Dec-20	0.153204
Oct-17	0.532534	Jan-21	0.143847
Nov-17	0.511285	Feb-21	0.134491
Dec-17	0.490037	Mar-21	0.125134
Jan-18	0.480680	Apr-21	0.115778
Feb-18	0.471324	May-21	0.106421
Mar-18	0.461967	Jun-21	0.097065
Apr-18	0.452611	Jul-21	0.087708
May-18	0.443255	Aug-21	0.078352
Jun-18	0.433898	Sep-21	0.068995
Jul-18	0.424542	Oct-21	0.059639
Aug-18	0.415185	Nov-21	0.050282
Sep-18	0.405829	Dec-21	0.040926
Oct-18	0.396472	Jan-22	0.034105
Nov-18	0.387116	Feb-22	0.027284
Dec-18	0.377759	Mar-22	0.020463
Jan-19	0.368403	Apr-22	0.013642
Feb-19	0.359046	May-22	0.006821
Mar-19	0.349690	Jun-22	0.000000

Exhibit K Page 1

Coal Supply Agreement

EXHIBIT L—PURCHASE PRICE ADJUSTMENT FACTORS (SJCC EVENT OF DEFAULT)



Jan-16	0.978752	Apr-19	0.340333
Feb-16	0.957503	May-19	0.330977
Mar-16	0.936255	Jun-19	0.321620
Apr-16	0.915006	Jul-19	0.312264
May-16	0.893758	Aug-19	0.302907
Jun-16	0.872509	Sep-19	0.293551
Jul-16	0.851261	Oct-19	0.284194
Aug-16	0.830012	Nov-19	0.274838
Sep-16	0.808764	Dec-19	0.265481
Oct-16	0.787515	Jan-20	0.256125
Nov-16	0.766267	Feb-20	0.246768
Dec-16	0.745018	Mar-20	0.237412
Jan-17	0.723770	Apr-20	0.228055
Feb-17	0.702522	May-20	0.218699
Mar-17	0.681273	Jun-20	0.209343
Apr-17	0.660025	Jul-20	0.199986
May-17	0.638776	Aug-20	0.190630
Jun-17	0.617528	Sep-20	0.181273
Jul-17	0.596279	Oct-20	0.171917
Aug-17	0.575031	Nov-20	0.162560
Sep-17	0.553782	Dec-20	0.153204
Oct-17	0.532534	Jan-21	0.143847
Nov-17	0.511285	Feb-21	0.134491
Dec-17	0.490037	Mar-21	0.125134
Jan-18	0.480680	Apr-21	0.115778
Feb-18	0.471324	May-21	0.106421
Mar-18	0.461967	Jun-21	0.097065
Apr-18	0.452611	Jul-21	0.087708
May-18	0.443255	Aug-21	0.078352
Jun-18	0.433898	Sep-21	0.068995
Jul-18	0.424542	Oct-21	0.059639
Aug-18	0.415185	Nov-21	0.050282
Sep-18	0.405829	Dec-21	0.040926
Oct-18	0.396472	Jan-22	0.034105
Nov-18	0.387116	Feb-22	0.027284
Dec-18	0.377759	Mar-22	0.020463
Jan-19	0.368403	Apr-22	0.013642
Feb-19	0.359046	May-22	0.006821

Exhibit L Page 1

Coal Supply Agreement



Mar-19	0.349690	Jun-22	0.000000

Exhibit L Page 2

Coal Supply Agreement

EXHIBIT M—ALLOCATION METHODOLOGY FOR ANNUAL PREEXISTING STOCKPILE AMOUNT

The Annual Preexisting Stockpile Amount shall be determined for each Contract Year of the Term in the following manner:

After determination of the Preexisting Stockpile Volume, such amount shall be allocated in the following order of Contract Years at one million five hundred thousand (1,500,000) tons per Contract Year but in no year more than the Tier 1 Tons (with any remainder less than one million five hundred thousand tons allocated in sequence) until the Preexisting Stockpile Volume has been fully allocated: 2016 Contract Year, 2017 Contract Year, 2022 Contract Year, 2021 Contract Year, 2020 Contract Year, 2019 Contract Year, and 2018 Contract Year.

An example allocation is shown in the table below assuming a Preexisting Stockpile Volume of 4,853,121 tons.



Annual Preexisting Stockpile Amount
Total	2016	2017	2018	2019	2020	2021	2022
4,853,121	1,500,000	1,500,000	0	0	0	453,121	1,400,000

Exhibit M Page 1

EXHIBIT N—QUARTERLY PRICE ADJUSTMENT

Exhibit N Page 1

EXHIBIT O—FORM OF ASSIGNMENT AND ASSUMPTION OF COAL SUPPLY AGREEMENT

For good and valuable consideration, the receipt and adequacy of which is hereby acknowledged, Westmoreland Coal Company, a Delaware corporation (“Westmoreland”), hereby transfers and assigns to San Juan Coal Company, a Delaware corporation (“SJCC”), and SJCC hereby assumes, all of Westmoreland’s rights and obligations under that certain Coal Supply Agreement, dated as of July 1, 2015, by and between Westmoreland and Public Service Company of New Mexico, a New Mexico corporation. This assignment is effective as of [________, 20__].

WESTMORELAND COAL COMPANY

By: ________________________________

Name:

Title:

SAN JUAN COAL COMPANY

By: ________________________________

Name:

Title:

Exhibit O Page 1

Execution Version

Underground Coal Sales Agreement Termination

and Mutual Release Agreement

Among

San Juan Coal Company

And

BHP Billiton New Mexico Coal, Inc.

And

Public Service Company of New Mexico

And

Tucson Electric Power Company

Signature Page to UGCSA Termination

Signature of San Juan Coal Company and BHP Billiton New Mexico Coal, Inc.

Section 0 - Parties and Recitals

THIS UNDERGROUND COAL SALES AGREEMENT TERMINATION AND MUTUAL RELEASE AGREEMENT (“Agreement”) dated July 1, 2015, is between SAN JUAN COAL COMPANY, a Delaware corporation (herein "SJCC"), BHP BILLITON NEW MEXICO COAL, INC., a Delaware corporation (“BBNMC”), and PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“PNM”), and TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“TEP”) (herein collectively referred to as "Utilities"), (with SJCC, BBNMC, and Utilities herein sometimes collectively referred to as "Parties").

RECITALS

WHEREAS, except for BBNMC, the Parties are parties to the Underground Coal Sales Agreement dated August 31, 2001, with an effective date of January 1, 2003, as amended from time to time (“UG-CSA”);

WHEREAS, contemporaneous with the closing of the sale of 100% of SJCC’s stock from BBNMC to Westmoreland Coal Company (“Purchaser”) under the Stock Purchase Agreement (as defined below), the Parties desire to terminate the UG-CSA and replace it with a new Coal Supply Agreement between PNM and SJCC;

WHEREAS, under the Stock Purchase Agreement, BBNMC is entitled to amounts due under the UG-CSA through the invoicing process set forth in this Agreement; and

WHEREAS, the purpose of this Agreement is to set forth the agreement between the Parties for the termination of the UG-CSA, and the processes by which the Parties intend to wind up the rights and obligations of the Parties to the UG-CSA.

NOW, THEREFORE, in consideration of the terms, covenants and agreements contained in this Agreement, Utilities jointly and severally agree with SJCC and BBNMC as follows:

AGREEMENT

Section 1 - Definitions

All capitalized terms used but not defined in this Agreement shall have the meaning set forth in the UG-CSA. Also, additional terms are defined throughout this Agreement. When used in this Agreement, the terms defined in this Section 1 shall have the following meanings.


1.1	Closing means the closing of the transaction under the Stock Purchase Agreement.


1.2	CSA means the new Coal Supply Agreement between PNM and Purchaser (which agreement provides, among other things, for the assignment of Purchaser’s rights and obligations thereunder to SJCC as of the Closing), dated July 1, 2015.


1.3	Purchaser means Westmoreland Coal Company, a Delaware corporation, which

shall acquire at the Closing 100% of the stock of SJCC and San Juan Transportation Company (“SJTC”) pursuant to the terms of the Stock Purchase Agreement.


1.4	Stock Purchase Agreement means that certain Stock Purchase Agreement entered into between BBNMC and Purchaser, dated July 1, 2015, agreeing, among other things, to the sale and purchase of 100% of the stock of SJCC and SJTC.

Section 2 - Effective Date and Representations


2.1	Effective Time

Sections 1, 2, 8 and 9 of this Agreement shall be effective upon execution of this Agreement by all of the Parties. Sections 3, 4, 5, 6 and 7 of this Agreement shall be effective contemporaneous with the Closing and the effectiveness of the CSA and until such time shall have no force and effect.


2.2	Automatic Termination, etc.

This Agreement shall immediately terminate and have no force and effect in the event of a termination of the Stock Purchase Agreement pursuant to Section 8.1 thereof.

In the event of a delay in Closing beyond December 31, 2015, the Parties agree to cooperate in good faith to: (a) revisit the invoicing provisions contained in Section 4 to ensure a smooth and fair final invoicing process; and (b) adjust the obligations of SJCC and the Utilities under the UG-CSA and this Agreement, as may be necessary and appropriate.


2.3	Representations and Warranties

As of the execution of this Agreement and subject to satisfaction of the applicable conditions precedent described in this Agreement, each Party warrants and represents that:


(A)	it is a corporation duly organized and in good standing in its state of incorporation and is qualified to do business and is in good standing in those states where necessary in order to carry out the purposes of this Agreement;


(B)	it has the capacity to enter into and perform this Agreement and all transactions contemplated in this Agreement, and that all corporate actions required to authorize it to enter into and perform this Agreement have been taken properly;


(C)	this Agreement has been duly executed and delivered by it and is valid and binding upon it in accordance with its terms; and


(D)	To the knowledge of such Party, there are no defaults, breaches or claims

existing under the UG-CSA as between the parties to the UG-CSA.

Section 3 - Termination of the UG-CSA; Reimbursement; Taxes


3.1	UG-CSA Termination; Exceptions; Scope

Except as otherwise set forth in this Agreement, the UG-CSA, specifically including without limitation all provisions described in the UG-CSA as surviving termination or expiration of the UG-CSA, is hereby terminated and of no further force and effect. For the avoidance of doubt, the Parties intend that those obligations, including without limitation the obligations provided in UG-CSA Sections 2.1(D), 2.2(B), 7.3, 12.5(D), 12.6(D), and 14.18, will not survive the termination of the UG-CSA in accordance with this Agreement.

3.2 Pre-Closing Taxes and Royalties; Reimbursement

Notwithstanding anything to the contrary contained herein, (A) if (i) BBNMC is required to and pays pursuant to Section 5.3 of the Stock Purchase Agreement any Taxes (as defined in the Stock Purchase Agreement) for any Pre-Closing Date Tax Periods (as defined in the Stock Purchase Agreement), and (ii) such Taxes would have otherwise been reimbursable by the Utilities as “Operating Costs” (as defined in Exhibit F of the UG-CSA) under the UG-CSA, then the Utilities shall reimburse BBNMC for the amount of such Taxes, and (B) if BBNMC is entitled to and receives pursuant to Section 5.3(h) of the Stock Purchase Agreement any overpayment, refunds or credits for Taxes for any Pre-Closing Date Tax Periods, and (B) such Taxes would have otherwise been refundable to the Utilities under the UG-CSA, then the Party that received the overpayment, refund or credit shall pay to the Utilities the amount of such overpayment, refund or credit.

Notwithstanding anything to the contrary contained herein, if (i) SJCC is required to and pays any retroactively assessed royalties pursuant to the Continuous Highwall Mining Royalty Rate Dispute with the U.S. Minerals Management Service, a 2013 U.S. Bureau of Land Management Regulatory Rulemaking Proceeding seeking designation of highwall mining as surface mining for royalty rate purposes, for any period prior to the Closing, and (ii) such retroactively assessed royalties would have otherwise been reimbursable by the Utilities as “Operating Costs” (as defined in Exhibit F of the UG-CSA) under the UG-CSA, then the Utilities shall reimburse SJCC for the amount of such retroactively assessed royalties.

Section 4 - Final UG-CSA Invoicing and Payment


4.1	Final December 2015 Invoicing Process

SJCC and BBNMC shall cooperate to prepare and submit to Utilities final year end invoices (“Final December 2015 Invoices”) as provided in Section 8.7 of the UG-CSA. To the extent the Parties refer to Section 8.7 of the UG-CSA for final invoicing purposes, Section 8.7 shall survive termination of the UG-CSA only for those purposes. The invoiced amounts submitted to the Utilities shall be paid to

BBNMC. If any amounts invoiced to the Utilities pursuant to this Agreement are paid to SJCC, SJCC shall pay those amounts to BBNMC promptly after receipt by SJCC. BBNMC and the Utilities will work in good faith to settle any disagreements relating to the Final December 2015 Invoices during the thirty (30) day period following delivery thereof from BBNMC to the Utilities. Following resolution of any such dispute, an actual “true-up” invoice for 2015 shall be prepared and agreed by the Parties, and immediate payment shall be made from Utilities to BBNMC or from BBNMC to the Utilities, as the case may be, to account for the difference between the estimated and actual “true-up” Invoice for 2015.


4.2	BBNMC and SJCC Cooperation

BBNMC and SJCC shall cooperate in good faith to effectuate the invoicing and Utilities’ invoice verification rights provided in this Agreement.

Section 5 - Audits of UG-CSA Invoices; Waiver


5.1	Completed Audits

Audits under the UG-CSA are complete and closed through Calendar Year 2009. The Utilities have no further rights to audit, verify or otherwise inspect invoices, books, records or other documentation SJCC has maintained or rendered for periods through December 31, 2009. SJCC also has no further rights to revise or otherwise seek any adjustments to past invoices for periods prior to December 31, 2009.


5.2	Audit Rights; Waiver of Further Audit Rights

Any audits for Calendar Years 2010, 2011, 2012, 2013, 2014 and 2015 are hereby waived (other than Utilities’ right to confirm the amounts of Final December 2015 Invoices as contemplated above), and SJCC also waives any rights it may have to revise or otherwise seek any adjustments to past invoices for the period(s) for which audits are waived; provided however that BBNMC shall have the right to submit Final December 2015 Invoices as contemplated in this Agreement. Upon Utilities' request, BBNMC and/or SJCC shall supply Utilities, by report and/or with actual source documents, the information reasonably necessary to verify the Final December 2015 Invoices; provided, however, that BBNMC and SJCC shall not be required to disclose information which in its reasonable opinion is of a confidential nature due to the relationship of such information to SJCC's operations.

Section 6- Release of the Parties’ Obligations

EXCEPT TO THE EXTENT SPECIFIC OBLIGATIONS ARE DESCRIBED IN OTHER SECTIONS OF THIS AGREEMENT, INCLUDING WITHOUT LIMITATION BY REFERENCE TO THE UG-CSA, EFFECTIVE AS OF THE CLOSING, BBNMC,

SJCC, AND THE UTILITIES, FOR THEMSELVES, AND ALL SAN JUAN STATION OWNERS, IN EACH CASE INCLUDING, AFFILIATES, SUCCESSORS AND ASSIGNS THEREOF (EACH, A “RELEASING PARTY"), DOES HEREBY RELEASE AND ABSOLUTELY FOREVER DISCHARGE THE OTHER PARTIES AND THEIR AFFILIATES (THE "UG-CSA RELEASED PARTIES") FROM AND AGAINST ALL UG-CSA RELEASED MATTERS. "UG-CSA RELEASED MATTERS" MEANS ANY AND ALL CLAIMS, DEMANDS, DAMAGES, INDEBTEDNESS, LIABILITIES, OBLIGATIONS, COSTS, EXPENSES (INCLUDING ATTORNEYS' AND ACCOUNTANTS' FEES AND EXPENSES), ACTIONS AND CAUSES OF ACTION OF ANY NATURE WHATSOEVER, WHETHER NOW KNOWN OR UNKNOWN, SUSPECTED OR UNSUSPECTED, THAT ANY RELEASING PARTY HAS, OR AT ANY TIME PREVIOUSLY HAD, OR SHALL OR MAY HAVE IN THE FUTURE, WITH RESPECT TO ANY OF THE UG-CSA RELEASED PARTIES: (A) WHICH ARISE FROM, OR ARE IN ANY MANNER RELATED TO THE UG-CSA AT ANY TIME AND (B) WHICH ARISE FROM, OR ARE IN ANY MANNER RELATED TO, THE CONDITION, MANAGEMENT, OPERATION, USE, OR LEASE OF THE SAN JUAN MINE, THE LA PLATA MINE, AND THE HAUL ROAD, AND LANDS SUBJECT TO ASSOCIATED AGREEMENTS AND RIGHTS-OF-WAY AT ANY TIME PRIOR TO THE CLOSING.

IT IS THE INTENTION OF THE RELEASING PARTIES IN EXECUTING THIS AGREEMENT, INCLUDING THIS MUTUAL RELEASE, AND IN GIVING AND RECEIVING THE CONSIDERATION CALLED FOR UNDER THIS AGREEMENT, THAT THE RELEASE CONTAINED IN THIS RELEASE SHALL BE EFFECTIVE AS A FULL AND FINAL ACCORD AND SATISFACTION AND GENERAL RELEASE OF THE UG-CSA RELEASED PARTIES FROM ALL UG-CSA RELEASED MATTERS AND THE FINAL RESOLUTION BY THE RELEASING PARTIES AND THE UG-CSA RELEASED PARTIES OF ALL UG-CSA RELEASED MATTERS. THE INVALIDITY OR UNENFORCEABILITY OF ANY PART OF THIS SECTION SHALL NOT AFFECT THE VALIDITY OR ENFORCEABILITY OF THE REMAINDER OF THIS RELEASE, WHICH SHALL REMAIN IN FULL FORCE AND EFFECT. EACH RELEASING PARTY HEREBY REPRESENTS AND WARRANTS THAT IT HAS NOT KNOWINGLY ASSIGNED OR TRANSFERRED OR PURPORTED TO ASSIGN OR TRANSFER TO ANY PERSON ANY UG-CSA RELEASED MATTER.

THE PROVISIONS OF THIS SECTION 6 SHALL NOT APPLY TO A CLAIM FOR BREACH OF THIS AGREEMENT.

Section 7 - Termination and Release of BHP Minerals International, LLC, Guarantor

Effective as of the Closing, the Utilities hereby terminate the Parent Guarantee, dated January 1, 2008, executed by BHP Minerals International, LLC and hereby release BHP Minerals International, LLC from any and all obligations it may have or have had as Guarantor or in any other capacity under the UG-CSA. For the avoidance of doubt, this release is to include guarantees of any other BHP Billiton entities from other commitments to the Utilities or any of them arising from the UG-CSA or any other

related agreements, including without limitation: (a) the August 18, 1980 Grant of Authority; and (b) the 1996 letter agreement associated with the formation of BNCC.

Section 8 - Dispute Resolution


8.1	Matters To Be Arbitrated; Notice of Claims and Defenses; Party Arbitrator Designation

Any Party may demand final and binding arbitration of any dispute, claim or controversy arising out of or relating to this Agreement, performance or actions pursuant to this Agreement, or concerning the interpretation of this Agreement (whether such matters sound in contract, tort or otherwise and including without limitation repudiation, illegality, and/or fraud in the inducement) by giving written notice to the other Parties of all claims it desires to submit to arbitration. The notice shall include a detailed statement of the facts and theories supporting the claims. The Parties on whom the arbitration demand is served shall have thirty days from receipt of the notice to respond in writing to the demand and to submit any additional claims such Parties wish to submit to arbitration at the same time. Each such Party’s response also shall include a detailed statement of the facts and theories supporting the claims and/or defenses asserted. The Party originally demanding arbitration shall reply in writing to any additional claims submitted within ten days from the receipt of such response.


8.2	Selection of Arbitrators

By agreement of the Parties, the Parties shall seek the assistance of the American Arbitration Association (“AAA”) to select an arbitrator from its roster of neutral arbitrators. That arbitrator shall serve as the sole arbitrator to hear and resolve the disputes presented. If for any reason, the AAA arbitrator selection process fails, the Parties shall petition the Chief Judge of the United States District Court for the District of New Mexico for the appointment of an arbitrator. The Parties shall be equally liable for the reasonable fees and expenses of the neutral arbitrator hearing the dispute.


8.3	Arbitration Hearings, Procedures and Timing

All reasonable efforts will be made to hold a hearing on the claims submitted within sixty days after the appointment of the arbitrator. In conducting the hearing, the arbitrator is directed, where feasible and where not inconsistent with the provisions of this section, to adhere to the then-existing American Arbitration Association procedures and rules relating to commercial disputes. Unless otherwise agreed by the Parties, the hearing shall be held in Farmington, New Mexico.


8.4	Choice of Law

The arbitrator shall apply the laws of the State of New Mexico.


8.5	Award and Enforcement

The decision or award of the arbitrator shall be given in writing within thirty days after the conclusion of the hearing. The arbitrator is authorized to award money damages, injunctive and declaratory relief and/or specific performance, if such relief in his or her opinion is appropriate. In any arbitration, each Party shall bear its own costs, expenses, and attorneys' fees. The arbitrator does not have authority to award costs, expenses, or attorneys' fees to the prevailing Party. The award or decision of the arbitrator shall be subject to review or enforcement in accordance with the New Mexico Uniform Arbitration Act, NMSA 1978 §§ 44-7-1 et seq. Any Party shall be entitled to recover reasonable attorneys' fees and costs incurred in enforcing any arbitration award or decision made pursuant to the arbitration provisions of this Agreement.


8.6	Performance Pending Arbitration Decision

During the arbitration, unless otherwise ordered by the arbitrator, the Parties shall continue to perform under this Agreement.


8.7	Definition of “Party” for this Section

For purposes of this Section 8, the Utilities shall be considered a single Party.

Section 9 - General Provisions


9.1	Confidentiality / Non-disclosure

The Parties consider the terms and conditions set forth in this Agreement to be confidential and proprietary information and none of the Parties shall disclose any such information to any third party other than the attorneys, auditors and agents of Utilities, other owners of the San Juan Station, SJCC, and BBNMC without the advance written consent of the other Parties; provided, however, disclosure may be made without advance consent where, in the opinion of counsel, such disclosure may be required by order of court or regulatory agency, law or regulation or in connection with judicial or administrative proceedings involving a Party hereto, in which event the Party to make such disclosure shall advise the other in advance as soon as possible and cooperate to the maximum extent practicable to minimize the disclosure of any such information.

Utilities shall maintain with the owners of the San Juan Station other than the Utilities written confidentiality agreements that are acceptable to SJCC and BBNMC prior to the disclosure of the terms of this Agreement.


9.2	The Utilities’ Duties and Obligations Shall be Joint and Several

The Utilities’ duties and obligations under this Agreement shall be joint and several.


9.3	Notices


A)	Any notice, demand or request provided for in this Agreement, or given or made in connection with this Agreement, shall be in writing, signed by an

officer of the Party giving such notice and shall be deemed to be properly and sufficiently given or made if sent by registered or certified mail, and if to SJCC, addressed as follows:

San Juan Coal Company

300 West Arrington, Suite 100

Farmington NM, 87401

Attention: President

with a copy addressed as follows:

San Juan Coal Company

Post Office Box 155

Fruitland, NM 87416

Attention: San Juan Mine Manager

and if to BBNMC, addressed as follows:

BHP Billiton New Mexico Coal. Inc.

300 West Arrington, Suite 100

Farmington NM, 87401

Attention: President

and if to Utilities, addressed as follows:

Public Service Company of New Mexico

Alvarado Square

Albuquerque, NM 87158

Attention: Corporate Secretary

and

Tucson Electric Power Company

Post Office Box 711

Tucson, AZ 85702

Attention: Secretary


B)	Any Party hereto may change its address for notice by so advising the other Parties hereto in accordance with the provisions of this Section 9.3. Any notice given in accordance with the provisions of this Section 9.3 shall be deemed effectively given as of the date of its deposit with the United States Postal Service.


9.4	Choice of Law

The terms and provisions of this Agreement shall be interpreted and construed in accordance with the laws of the State of New Mexico, without regard to conflict of law principles.


9.5	Successors and Assigns

This Agreement and all of the obligations and rights herein established shall extend to and be binding upon, and shall inure to the benefit of, the respective successors and assigns of the respective Parties.


9.6	Authorizations

The execution and performance by the Parties of this Agreement have been duly authorized for each Party by all necessary corporate action, require no other authorization, consent or approval and do not contravene any law or contractual restriction binding on the Parties.


9.7	Amendments

This Agreement may be amended only by written instrument executed by all of the Parties with the same formality as this Agreement.


9.8	Construction

The terms and conditions of this Agreement are the result of negotiation and drafting on an equal footing by the Parties and their legal counsel. This Agreement shall be construed evenhandedly and without favor or predisposition to any Party. The titles of sections in this Agreement have been inserted as a matter of convenience or for reference only, and they shall not control or affect the meaning or construction of any of the terms and provisions hereof.


9.9	Entire Agreement


9.10	Waiver of Consequential and Punitive Damages.

BBNMC, SJCC, and the Utilities waive any recovery of consequential and punitive damages related to the breach of this Agreement.


9.11	Severability

[This space intentionally left blank.]

Section 10 - Signatures

IN WITNESS WHEREOF , the Parties hereto have caused this Agreement to be executed on their behalf by their respective officers, thereunto duly authorized, as of the day and year first herein written.

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _____ _______________

Name: _____ _______________

Title: _____ ___

TUCSON ELECTRIC POWER COMPANY

By: ______ /s/ Mark C. Mansfield _____________

Name: ______ Mark C. Mansfield _____________

Title: ______ VP Energy Resources ___________

SAN JUAN COAL COMPANY

By: _ _______________________

Pat D. Risner, President

BHP BILLITON NEW MEXICO COAL, INC.

By: ___ _______________________

Pat D. Risner, President

FINAL

IN WITNESS WHEREOF , the Parties hereto have caused this Agreement to be executed on their behalf by their respective officers, thereunto duly authorized, as of the day and year first herein written.

SAN JUAN COAL COMPANY

By: _ /s/ __ Pat D. Risner _______________________

Pat D. Risner, President

BHP BILLITON NEW MEXICO COAL, INC.

By: _ /s/ __ Pat D. Risner _______________________

Pat D. Risner, President

Section 10 - Signatures

IN WITNESS WHEREOF , the Parties hereto have caused this Agreement to be executed on their behalf by their respective officers, thereunto duly authorized, as of the day and year first herein written.

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _____ /s/ Chris M. Olson _________

Name: ____ Chris M. Olson ______________

Title: ___ Vice President, Generation ___

TUCSON ELECTRIC POWER COMPANY

By: _________ _________

Name: ______________ ___

Title: _____ _________

SAN JUAN COAL COMPANY

By: _ _______________________

Pat D. Risner, President

BHP BILLITON NEW MEXICO COAL, INC.

By: ___ _______________________

Pat D. Risner, President

Signature Page to UGCSA Termination

Signature of San Juan Coal Company and BHP Billiton New Mexico Coal, Inc.

EXECUTION VERSION

SAN JUAN PROJECT RESTRUCTURING AGREEMENT

AMONG

PUBLIC SERVICE COMPANY OF NEW MEXICO

TUCSON ELECTRIC POWER COMPANY

THE CITY OF FARMINGTON, NEW MEXICO

M-S-R PUBLIC POWER AGENCY

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

CITY OF ANAHEIM

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

July 31, 2015

EXECUTION VERSION

SAN JUAN PROJECT RESTRUCTURING AGREEMENT

TABLE OF CONTENTS



RECITALS	1
1. Effective Date and Termination	4
1.1 Effective Date	4
1.2 FERC Filings	4
1.3 Filings with Governmental Agencies	5
1.4 Review of Regulatory Orders	5
1.5 Appellate Decision	6
1.6 Actions not Arbitrable	6
1.7 Termination Date	6
2. Definitions and Rules of Interpretation	6
2.1 Definitions	6
2.2 Rules of Interpretation	15
3. Status of PNMR-D under SJPPA	16
3.1 PNMR-D as Party to SJPPA	16
3.2 Parental Guaranty and Letter of Credit	17
4. Restructuring Fee, Demand Charge and Voting	17
4.1 Restructuring Fee	17
4.2 Payment of Restructuring Fee and Common Participation Shares of Shared Coal Inventory	18
4.3 Costs of Capital Improvements Invoiced after January 1, 2015	18
4.4 Demand Charge	19
4.5 Voting on Capital Improvements	20
5. Fuel Supply	20
5.1 Certain Cost Allocations	20
5.2 Supply of Coal to Exiting Participants and Remaining Participants	21
5.3 Relinquishment of Coal Inventory	21
5.4 Coal Supply for Exiting Participants	21
5.5 Minimum Purchase Obligations	21
5.6 Existing Participant Dispatch Requirements; Invoicing	21
5.7 Monthly Remaining Participant Coal Invoicing	21
5.8 Section 23.14 Superseded	24

EXECUTION VERSION



6. Exit Date and Ownership Conveyances	24
6.1 Transfer of Existing Participants' Rights	24
6.2 Acquisition of Ownership Interests of Existing Participants	24
6.3 Plant Ownership after Acquisition of Ownership Interest of Exiting Participants	25
6.4 Unit 1 and Unit 2 Ownerships After Exit Date	25
6.5 "AS IS" Conveyances	25
7. Closing of Ownership Conveyances	25
7.1 Closing	25
7.2 Closing Statement	26
7.3 Closing Deliveries by the Exiting Participants	26
7.4 Closing Deliveries by the Acquiring Participants	27
7.5 Conditions Precedent	27
7.6 Prior Notification of Certain Events	28
7.7 Prorations	28
7.8 Governmental Recording and Filing	28
8. Notifications, Consents and Rights-of-First-Refusal	28
9. Operation and Maintenance Expenses	28
10. Replacement Power	29
11. Other Project Agreements	29
11.1 Other Project Agreements Identified	29
11.2 Actions with Respect to Other Project Agreements	29
12. Land Ownership	29
12.1 No Change in Ownership	29
12.2 Relinquishment of Certain Rights	29
12.3 Easement and Right of Entry	29
13. Coal Mine Reclamation Funding	29
14. Decommissioning	29
15. Confidentiality	30
15.1 Confidentiality of Negotiations	30
15.2 Non-confidentiality of Restructuring Agreement	30
16. Taxes	30
16.1 Obligations of Parties	30
16.2 Notification of Taxing Authorities	30
16.3 IRS Exclusion	30

EXECUTION VERSION



17. Representations and Warranties; Opinions of Counsel	31
17.1 Requisite Power and Authority	31
17.2 No Violation	31
17.3 Opinions of Counsel	31
18. Relationship of Parties	31
18.1 Several Obligations	31
18.2 No Joint Venture or Partnership	32
19. Establishment of Environmental Baseline	32
19.1 Baseline Environmental Study	32
19.2 Scope of BES and Environmental Audit	32
19.3 Draft Report	33
19.4 Final Report	33
19.5 Remediation or Corrective Action	33
19.6 Further Audit	33
19.7 Subsequently Discovered Environmental Issues	34
19.8 Claims against Predecessors	34
20. Liability and Indemnification	34
20.1 Liabilities Defined	34
20.2 Liabilities Arising Prior to Exit Date	34
20.3 Liabilities Arising After Exit Date	34
20.4 Apportionment of Liabilities	35
20.5 Limitation of Liability for Willful Action	35
20.6 Several Liability	35
20.7 Claims Arising After Exit Date	35
20.8 Claims against Predecessors	37
20.9 PNM Responsibility	37
20.10 Indemnification Procedures	37
20.11 Anti-Indemnity Provisions	39
20.12 Internal Counsel	39
20.13 Willful Action	39
20.14 Damages	39
20.15 Mitigation of Damages	39
20.16 Anaheim and M-S-R	39
20.17 Southern California Public Power Authority	40

iii

EXECUTION VERSION



20.18 Farmington and Los Alamos	40
20.19 Utah Associated Municipal Power Systems	40
21. Insurance Coverage for Continuing Obligations	40
21.1 Occurrence-based Policies	40
21.2 Claims-Made Policies	40
21.3 Other Insurance Coverage Matters	42
22. Assignments	42
22.1 Assignment	42
22.2 Assignee Responsibility	43
22.3 Parties not Relieved of Obligations	43
23. Dispute Resolution and Default	43
23.1 Amicable Resolution	43
23.2 Call for Arbitration	44
23.3 Selection of Arbitrators	45
23.4 Arbitration Procedures	46
23.5 Decision of Arbitrators	46
23.6 Enforcement of Arbitration Award	46
23.7 Fees and Expenses	46
23.8 Interest and Penalty Interest	46
23.9 Prompt Resolution	46
23.10 Default	47
23.11 Consequence of Default	47
23.12 Legal Remedies	47
24. Audit Rights; Related Disputes	47
24.1 Right of Audit	47
24.2 Dispute Resolution	47
24.3 Adjusted Billing Procedures	48
24.4 Effectiveness	48
25. Miscellaneous Provisions	48
25.1 Governing Law	48
25.2 Venue	48
25.3 Manner of Giving Notice	48
25.4 Other Documents	51
25.5 Incorporation of Exhibits	51

EXECUTION VERSION



25.6 Captions and Headings	51
25.7 Prior Obligations Unaffected	51
25.8 Amendment and Modification	51
25.9 Waivers of Compliance	51
25.10 Uncontrollable Forces	51
25.11 No Interpretation against Drafter	52
25.12 No Third Party Beneficiaries	52
25.13 Compliance with Law	52
25.14 Independent Covenants	52
25.15 Invalid Provisions	52
25.16 Parties' Cost Responsibilities	52
25.17 Entire Agreement	53
25.18 Survival of Certain Provisions	53
25.19 No Admission of Liability	53
25.20 Other Rights	53
25.21 Execution in Counterparts	53

EXECUTION VERSION

List of Exhibits



Exhibit A	Regulatory Approvals
Exhibit B	Other Project Agreements
Exhibit C	Form of Instrument of Sale and Conveyance
Exhibit D	Form of Opinion of Counsel
Exhibit E	Parties’ Pre-Exit Date Ownership Interests in Project Facilities
Exhibit F	SJGS Plant Site
Exhibit G	Form of Instrument Relinquishing Easement and License
Exhibit H	Form of Easement and Right of Entry
Exhibit I	Form of Parental Guaranty
Exhibit J	Form of Letter of Credit
Exhibit K	Form of Bring-Down Opinion

EXECUTION VERSION

SAN JUAN PROJECT RESTRUCTURING AGREEMENT

This SAN JUAN PROJECT RESTRUCTURING AGREEMENT (“Restructuring Agreement”) is executed as of July 31, 2015 (“Execution Date”) by and among PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“PNM”); TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“TEP”); THE CITY OF FARMINGTON, NEW MEXICO, an incorporated municipality and a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Farmington”); M-S-R PUBLIC POWER AGENCY, a joint exercise of powers agency organized under the laws of the State of California (“M-S-R”); THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO, a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Los Alamos”); SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, a joint exercise of powers agency organized under the laws of the State of California (“SCPPA”); CITY OF ANAHEIM, a municipal corporation organized under the laws of the State of California (“Anaheim”); UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS, a political subdivision of the State of Utah (“UAMPS”); TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC., a Colorado cooperative corporation (“Tri-State”); and PNMR DEVELOPMENT AND MANAGEMENT CORPORATION, a New Mexico corporation (“PNMR-D”). The parties to this Restructuring Agreement are sometimes referred to individually as a “Party” and collectively as the “Parties.”

RECITALS

This Restructuring Agreement is made with reference to the following facts, among others:

A. The San Juan Project is a four-unit, coal-fired electric generation plant located in San Juan County, near Farmington, New Mexico, also known as the San Juan Generating Station (“SJGS” or the “Project”). On the Execution Date, the owners of the Project are: PNM, TEP, Farmington, M-S-R, Los Alamos, SCPPA, Anaheim, UAMPS and Tri-State; these entities, as the owners of the Project on the Execution Date, are sometimes referred to in this Restructuring Agreement as the “Participants.”

B. As specified in Sections 6.2.1, 6.2.2 and 6.2.3 of the Amended and Restated San Juan Project Participation Agreement dated March 23, 2006 (“SJPPA”), as of the Execution Date, SJGS Unit 1 and Unit 2 are owned by PNM (50%) and TEP (50%); Unit 3 is owned by PNM (50%), SCPPA (41.8%) and Tri-State (8.2%); and Unit 4 is owned by PNM (38.457%), M-S-R (28.8%), Farmington (8.475%), Los Alamos (7.2%), Anaheim (10.04%) and UAMPS (7.028%). Equipment and facilities associated with more than one SJGS Unit are owned in other ownership percentages, as specified in Sections 6.2.4, 6.2.5 and 6.2.6 of the SJPPA. As provided in the SJPPA, such ownership interests are undivided interests.

C. PNM and PNMR-D are wholly-owned subsidiaries of PNM Resources, Inc. PNMR-D intends, consistent with the provisions of this Restructuring Agreement, to acquire an

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EXECUTION VERSION

Ownership Interest in the Project on the Exit Date and, prior to the acquisition of such Ownership Interest in the Project, to assume certain obligations under this Restructuring Agreement and the SJPPA. PNMR-D is a party to this Restructuring Agreement but is not as of the Execution Date a Participant in the Project.

D. On August 22, 2011, the federal Environmental Protection Agency (“EPA”) published its Federal Implementation Plan (“FIP”) which included a Best Available Retrofit Technology (“BART”) determination to meet regional haze requirements for SJGS. The FIP required the installation of selective catalytic reduction (“SCR”) technology on all four Units by September 21, 2016. Thereafter, PNM (in its capacity as SJGS Operating Agent), the Governor of the State of New Mexico and the New Mexico Environmental Department (“NMED”) petitioned the United States Court of Appeals for the Tenth Circuit to review this EPA decision. In subsequent discussions between PNM, NMED, EPA and other stakeholders, PNM supported an alternative to the FIP (“BART Alternative”) that would be less costly than the FIP while also achieving significant environmental benefits. The specific terms of the BART Alternative were set forth in the EPA Term Sheet, discussed in Recital F.

E. On February 12, 2013, the Participants, through their Coordination Committee representatives, voted (with certain abstentions) to adopt a “Resolution of the San Juan Generating Station Coordination Committee Supporting the Term Sheet with EPA and NMED for the Settlement of the Dispute Relating to the U.S. Environmental Protection Agency Best Available Retrofit Technology Determination for the San Juan Generating Station.” The resolution, among other things, approved the EPA Term Sheet (addressed below in Recital F) and contemplated the use of good faith efforts to pursue the approvals necessary to support the implementation of the EPA Term Sheet.

F. On February 15, 2013, PNM, NMED and EPA entered into a Term Sheet (the “EPA Term Sheet”) reflecting the terms of a non-binding “tentative agreement” for certain actions intended to address pollution control requirements for SJGS under the federal Clean Air Act’s requirements for regional haze and interstate transport for visibility. The EPA Term Sheet provided for the retirement of Unit 2 and Unit 3 by December 31, 2017, and the installation of selective non-catalytic reduction (“SNCR”) technology on Unit 1 and Unit 4 by the later of January 31, 2016 or fifteen (15) months after EPA approval of the BART Alternative.

G. On September 5, 2013, the State of New Mexico approved the BART Alternative as a revision to New Mexico’s Regional Haze State Implementation Plan (“RH SIP”) and, thereafter, submitted the revision to EPA. Under the terms of the RH SIP, Units 2 and 3 will cease operations by December 31, 2017.

H. By letter dated March 10, 2014, PNM declared in its capacity as Operating Agent that it needed to commence studies, analysis, assessments and design related to the installation of the BART Alternative on Unit 4 in order to comply with the deadlines set forth in the EPA Term Sheet. By letter dated July 14, 2014, PNM declared in its capacity as Operating Agent that it needed to begin incurring capital expenditures for engineering, analysis, computational fluid dynamics modeling and geotechnical evaluation, which was the next phase of the SNCR/balanced draft project for Unit 4. By letter dated March 20, 2015, PNM declared in its

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EXECUTION VERSION

capacity as Operating Agent that it needed to begin incurring equipment fabrication and engineering costs necessary to adhere to the RH-SIP compliance schedule.

I. On October 9, 2014, the EPA issued a final rule approving the BART Alternative and New Mexico’s revised RH SIP and issued a separate final rule withdrawing the FIP. EPA’s rules became effective November 10, 2014.

J. The California legislature has enacted statutes, and the California Energy Commission has promulgated implementing regulations, limiting the ability of SCPPA, M-S-R and Anaheim to enter into certain life extension projects for coal-fired power plants, including SJGS.

K. As the result of, among other things, the developments described in the foregoing Recitals, the anticipated costs of environmental compliance at SJGS and the California laws and regulations referenced above, the Participants entered into discussions with respect to the restructuring of their respective rights and obligations in the Project. To accomplish this restructuring, several of the Participants are willing or desire to divest or terminate their ownership in the Project while other Participants and PNMR-D are willing or desire to retain, increase or acquire ownership in the Project.

L. To facilitate the discussions referenced in Recital K, the Participants retained the services of an independent mediator. Mediated negotiations commenced in January 2014. In light of PNMR-D’s willingness to acquire ownership in the Project, PNMR-D became involved in the mediation in early 2015.

M. On September 12, 2014, the Participants entered into the San Juan Generating Station Fuel and Capital Funding Agreement (“Funding Agreement”). The Funding Agreement was accepted for filing by the Federal Energy Regulatory Commission (“FERC”) with an effective date of July 1, 2014. The Funding Agreement terminated by its own terms.

N. PNM has filed an application with the New Mexico Public Regulation Commission (“NMPRC”) for approvals required under the New Mexico Public Utility Act for, among other things, approval to abandon SJGS Units 2 and 3 and for a certificate of public convenience and necessity for PNM to own 132 MW of additional capacity in SJGS Unit 4.

O. Concurrently herewith, the Parties are executing: (i) the Amended and Restated Mine Reclamation and Trust Funds Agreement (“Mine Reclamation Agreement”); (ii) the San Juan Decommissioning and Trust Funds Agreement (“Decommissioning Agreement”); (iii) the SJPPA Restructuring Amendment; and (iv) the SJPPA Exit Date Amendment.

P. The Parties desire, by the agreements referenced in Recital O, to establish a comprehensive set of binding agreements with respect to the restructuring of Project ownership interests, rights and cost responsibilities.

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EXECUTION VERSION

Q. The terms, covenants and conditions set out herein are acceptable to each of the Parties and will promote the ability of each Party to provide adequate, efficient, reliable and economical service to its customers in a manner consistent with its legal obligations.

R. The foregoing Recitals are included to provide background regarding this Restructuring Agreement, and while certain Recitals may be referenced in this Restructuring Agreement, they are neither part of nor incorporated into the terms, covenants and conditions of this Restructuring Agreement.

AGREEMENT

NOW, THEREFORE, for and in consideration of the promises and obligations reflected in the covenants, terms and conditions in this Restructuring Agreement, all of which together provide the consideration for this Restructuring Agreement, the Parties agree as follows:

1. Effective Date and Termination

1.1 Effective Date . Conditioned upon due execution and delivery of this Restructuring Agreement by all of the Parties, the effective date of this Restructuring Agreement (“Effective Date”) is the date of the last to occur of the following: (i) FERC has approved the FPA Section 203 applications and has accepted for filing the FPA Section 205 application referenced in Section 1.2.1, in each case without conditions or with conditions acceptable to the Parties as provided in Section 1.4; (ii) the NMPRC has granted PNM authority to abandon Units 2 and 3 and has also granted a certificate of public convenience and necessity to own an additional interest in Unit 4, without conditions or with conditions acceptable to the Parties as provided in Section 1.4; or (iii) the effective date of the CSA.

1.2 FERC Filings .

1.2.1 Within fifteen (15) Business Days after the Execution Date (i) PNM and PNMR-D will file applications with FERC under Section 203 of the FPA for approval of the transactions provided for in Section 6, with a request for expedited consideration; and (ii) PNM will file an application with FERC under Section 205 of the FPA for acceptance of an amendment to the SJPPA incorporating relevant provisions of this Restructuring Agreement. The aforementioned amendment to the SJPPA (the “SJPPA Restructuring Amendment”) is being executed by the Parties concurrently with the execution of this Restructuring Agreement. PNM will be responsible for the preparation and filing of the Section 205 application, and PNM and PNMR-D will be responsible for the preparation and filing of their respective Section 203 applications. At least ten (10) Business Days prior to making the Section 203 and 205 applications referenced in this Section 1.2.1, PNM and PNMR-D will provide drafts thereof to the other Parties. PNM’s Section 205 filing of the SJPPA Restructuring Amendment will request that the effective date for the SJPPA Restructuring Amendment be the effective date of this Restructuring Agreement; provided, however, that such effective date is conditioned upon PNM providing notice to FERC that all of the other conditions for the effectiveness of this Restructuring Agreement, as identified in Section 1.1, have occurred. If necessary, PNM’s filing of the

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SJPPA Restructuring Amendment will request any waivers of FERC’s regulations that may be necessary to request an effective date for such revisions as specified in the previous sentence of this Section 1.2.1.

1.2.2 Additionally, prior to the Exit Date, PNM will file with FERC a further amendment to the SJPPA under FPA Section 205 (the “SJPPA Exit Date Amendment”) to reflect the exit from the Project of the Exiting Participants and to set forth the terms of the SJPPA under which the Remaining Participants will continue their participation in the Project, including the Remaining Participants’ operation and maintenance of Units 1 and 4 after the Exit Date. The SJPPA Exit Date Amendment is being executed by the Parties concurrently with the execution of this Restructuring Agreement. PNM will make this Section 205 filing of the SJPPA Exit Date Amendment not less than sixty (60) days nor more than one hundred twenty (120) days prior to the Exit Date and will request that the SJPPA Exit Date Amendment become effective on the Exit Date. At least ten (10) Business Days prior to filing the SJPPA Exit Date Amendment, PNM will provide a draft thereof to the other Parties.

1.2.3 If PNM and PNMR-D have complied with the obligation to provide drafts of the Section 203 and 205 filings set forth in Sections 1.2.1 and 1.2.2, and if such filings are consistent with the terms of this Restructuring Agreement, then all other Parties will support or not oppose PNM and/or PNMR-D’s FERC filings by the prompt filing at FERC of certificates or letters of concurrence; by intervening at FERC in support of the filings; or by not taking any action to oppose the filings.

1.3 Filings with Governmental Authorities . PNM and PNMR-D will provide each of the other Parties a copy of the FERC filings referenced in Sections 1.2.1 and 1.2.2, and will keep the other Parties reasonably apprised of the status of all filings to obtain Regulatory Approvals including copies of any Regulatory Approvals or other pertinent orders issued by Governmental Authorities with respect to such filings. PNM and PNMR-D will also provide each of the other Parties a copy of any motion for rehearing or reconsideration filed with respect to any Regulatory Approval and any notice of appeal or petition for review filed with respect to any Regulatory Approval within five (5) Business Days of receipt thereof, and in the manner provided in Section 25.3.

1.4 Review of Regulatory Orders .

1.4.1 Following issuance of an order by any Governmental Authority with regard to a Regulatory Approval, each Party will review such order to determine whether such Governmental Authority has (i) changed or modified a condition, deleted a condition or imposed a new condition with regard to the filing; or (ii) conditioned its approval of the filing upon changes or modifications to a condition, deletion of a condition or imposition of a new condition (the actions described in Sections 1.4.1(i) and 1.4.1(ii) hereinafter collectively referred to as “Regulatory Revision”). The Party receiving such order will provide a copy thereof to the other Parties in the manner provided in Section 25.3 within five (5) Business Days.

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1.4.2 Within ten (10) Business Days after delivery of the copy of the order, the Parties will provide written notice to each other of their acceptance or objection to the Regulatory Revision, specifying in such notice in the case of an objection each Regulatory Revision on which such objection is based and the reason for the objection. A failure to notify within said ten (10) Business Day period will be equivalent to a notification of acceptance of the Regulatory Revision.

1.4.3 If any Party objects to a Regulatory Revision, the Parties will attempt, in good faith, to renegotiate the terms and conditions of this Restructuring Agreement to resolve the Regulatory Revision leading to such objection to the satisfaction of the Parties and obtain necessary Board approvals within ninety (90) days after the date of notice of objection to such Regulatory Revision under Section 1.4.2, or such other period as the Parties may agree upon in writing.

1.4.4 If the Parties reach agreement on renegotiated terms and conditions, they will thereafter seek to obtain requisite Regulatory Approval of such renegotiated agreement, with any filings necessary to seek such Regulatory Approval being made within twenty (20) Business Days after the execution of the renegotiated agreement.

1.4.5 If the Parties fail to agree on such renegotiated terms and conditions within the ninety (90) day period referenced in Section 1.4.3, or such other period as the Parties may agree upon in writing, this Restructuring Agreement will not take effect.

1.5 Appellate Decision . A Party receiving a copy of an opinion or other decision affecting a Regulatory Approval or the terms or conditions thereof (“Decision”) of an appellate court will, within five (5) Business Days and in the manner provided in Section 25.3, provide a copy thereof to each other Party. Following receipt of the Decision, each Party will review the Decision to determine the potential effect of the Decision on the transactions provided for in this Restructuring Agreement. The Parties will confer in good faith regarding the effect, if any, of the Decision and will attempt, within seventy-five (75) days of receipt of a copy of the Decision, or such other period as the Parties may determine, to mutually agree upon the appropriate course of action in light of the Decision.

1.6 Actions not Arbitrable . Neither a dispute between or among the Parties arising under, nor a Party’s action or failure to act under this Section 1, is arbitrable under Section 23.

1.7 Termination Date . Unless otherwise agreed by the Parties, following the Effective Date, this Restructuring Agreement will continue until six (6) months after the later of the termination or expiration of (i) the Mine Reclamation Agreement; or (ii) the Decommissioning Agreement (the “Termination Date”).

2. Definitions and Rules of Interpretation

2.1 Definitions . The following terms, when used herein with initial capitalization, have the meanings specified below:

2.1.1 AAA means the American Arbitration Association.

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2.1.2 Acquiring Participants means PNM and PNMR-D.

2.1.3 Affiliate means with respect to any person: (i) each person that, directly or indirectly, controls or is controlled by or is under common control with such designated person; (ii) any person that beneficially owns or holds 50% or more of any class of voting securities of such designated person or 50% or more of the equity interest in such designated person; and (iii) any person of which such designated person beneficially owns or holds 50% or more of any class of voting securities or in which such designated person beneficially owns or holds 50% or more of the equity interest; provided, however, that members of a Party will not be deemed to be Affiliates of each such Party. For the purposes of this definition, “control” (including, with correlative meanings, the terms “controlled by” and “under common control with”), as used with respect to any person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such person, whether through the ownership of voting securities or by contract or otherwise; PNM and PNMR-D are Affiliates.

2.1.4 Arbitration Award means an award of the arbitrators, as provided for in Section 23.5.

2.1.5 Arbitration Notice has the meaning provided for in Section 23.2.

2.1.6 Arbitration Organization means an organization described in Section 23.3.2.

2.1.7 Available Pre-existing Stockpile Tons has the meaning provided for in Section 12.1(C)(1) of the CSA.

2.1.8 BART means Best Available Retrofit Technology.

2.1.9 BART Alternative means the alternative to the FIP, as identified in Recital D.

2.1.10 Baseline Environmental Study or BES means the study provided for in Section 19.1.

2.1.11 Board means the governing body of a Party.

2.1.12 Business Day means any day other than a Saturday, Sunday or federal holiday.

2.1.13 Capital Improvements means any property, land or land rights added to the Project or the substitution, replacement, enlargement or improvement of any units of property, structures, facilities, equipment, property, land or land rights constituting a part of the Project, which in accordance with accounting practice would be capitalized, and also including the costs of removal, salvage or disposal of any units of property being replaced or substituted.

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2.1.14 CCBDA means the existing Coal Combustion Byproducts Disposal Agreement between PNM, TEP and SJCC.

2.1.15 CCR means ash and gypsum byproducts produced by the Project.

2.1.16 CCRDA means the new Coal Combustion Residuals Disposal Agreement entered into between PNM and SJCC with an anticipated effective date of January 1, 2016.

2.1.17 Charter Documents means with respect to any Party, the certificate or articles of incorporation or organization and by-laws, the limited partnership agreement, the partnership agreement, the limited liability company agreement or trust agreement, or other organizational documents of such Party.

2.1.18 Claims-Made Policy has the meaning provided for in Section 21.2.1.

2.1.19 Clean Air Act means 42 U.S.C. § 7401 et seq . (1970).

2.1.20 Closing means the closing, as provided for in Section 7, of the conveyance of the Ownership Interests as provided for in Section 6.

2.1.21 Closing Date means the date of the Closing as provided for in Section 7.1.

2.1.22 Closing Statement has the meaning provided for in Section 7.2.

2.1.23 Coal Tonnage Components means coal tonnage categories as defined in the CSA and comprised of Pre-existing Stockpile Coal, Force Majeure Tons, Available Pre-existing Stockpile Tons, Tier 1 Tons, and Tier 2 Tons.

2.1.24 Common Participation Share means a Participant’s share of equipment and facilities common to all of the Units as set out in Section F in Exhibit E.

2.1.25 Common Participation Share of Shared Coal Inventory means a Party’s share of equipment and facilities common to all of the Units (as shown in Section F in Exhibit E) multiplied by the sum of (i) coal tons stockpiled on SJCC’s property, and (ii) coal tons stockpiled on the SJGS Plant Site.

2.1.26 Condition Precedent means an event that, unless waived, must occur prior to Closing as provided for in Section 7.5.

2.1.27 Consultant means the consultant retained pursuant to Section 19.1.

2.1.28 Continuing Coverage has the meaning provided for in Section 21.2.2.

2.1.29 Credit Rating means the rating publicly assigned to PNMR’s senior, unsecured long-term debt obligations (not supported by third-party credit enhancements)

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by a Rating Agency or, if PNMR does not have a public rating for its senior, unsecured long-term debt, the rating publicly assigned to PNMR by a Rating Agency as its corporate credit rating, or long term issuer rating, as applicable.

2.1.30 CSA means the new Coal Supply Agreement entered into between PNM and SJCC with an anticipated effective date of January 1, 2016.

2.1.31 Decision has the meaning provided for in Section 1.5.

2.1.32 Decommissioning Agreement means the San Juan Decommissioning and Trust Funds Agreement executed concurrently herewith.

2.1.33 Default has the meaning provided for in Section 23.10.

2.1.34 Draft Report means the draft report provided for in Section 19.3.

2.1.35 EAF means “equivalent availability factor” as defined in the North American Electric Reliability Corporation’s Generating Availability Data System Data Reporting Instructions.

2.1.36 Effective Date has the meaning provided for in Section 1.1.

2.1.37 Environmental Audit means the audit provided for in Section 19.1.

2.1.38 EPA means the federal Environmental Protection Agency or its successor agency.

2.1.39 EPA Term Sheet means the term sheet referenced in Recital F.

2.1.40 Escrow Interest has the meaning provided for in Section 23.8.

2.1.41 Execution Date has the meaning provided for in the introductory paragraph of this Restructuring Agreement.

2.1.42 Exit Date means the date upon which the Exiting Participants transfer all of their respective rights, titles and interests in and to their Ownership Interests to the Acquiring Participants as provided in Section 6 and terminate their active involvement in the operation of the SJGS, except as expressly provided for in this Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement; the Exit Date is anticipated to be on or about December 31, 2017.

2.1.43 Exiting Participants means those Participants that will transfer all of their respective rights, titles and interests in and to their Ownership Interests to the Acquiring Participants as provided in Section 6, and terminate their active involvement in the operation of SJGS on the Exit Date, except as expressly provided for in this Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement; the Exiting Participants are M-S-R, Anaheim, SCPPA and Tri-State.

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2.1.44 Federal Implementation Plan or FIP has the meaning provided for in Recital D.

2.1.45 Federal Power Act or FPA means 16 U.S.C. §§ 791a et seq .

2.1.46 FERC means the Federal Energy Regulatory Commission or any successor thereto.

2.1.47 Final Report means the final report provided for in Section 19.4.

2.1.48 Force Majeure Tons has the meaning provided for in Section 12.1(C)(1) of the CSA.

2.1.49 Fuels Committee means the committee established in the SJPPA to facilitate the discussion of Project coal issues.

2.1.50 Funding Agreement means the San Juan Generating Station Fuel and Capital Funding Agreement among the Participants, dated September 12, 2014.

2.1.51 Further Audit means the audit provided for in Section 19.6.

2.1.52 Governmental Authority means any federal, state, tribal, local, municipal or foreign governmental or regulatory authority, department, agency, commission, body, court or other governmental authority other than a Party.

2.1.53 Guaranteed Parties has the meaning provided for in the form of Parental Guaranty Agreement attached as Exhibit I.

2.1.54 Indemnified Party means a Party that is seeking or entitled to indemnification or is being indemnified, as provided in Section 20.10.1.

2.1.55 Indemnifying Party means a Party indemnifying another Party, as provided in Section 20.10.1.

2.1.56 Initiating Party means a Party initiating an audit as provided for in Section 24.1.

2.1.57 Law means statutes, rules, regulations, ordinances, orders and codes of federal, state and local Governmental Authorities.

2.1.58 Legacy Costs means those costs payable under Sections 8.2, 8.3 and 8.4 of the CSA

2.1.59 Letter of Credit has the meaning provided for in Section 3.2.2.

2.1.60 Liability means those liabilities described in Section 20.1.

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2.1.61 Liens and Encumbrances means, as to each Exiting Participant, all liens, mortgages, claims, assignments, taxes, assessments, governmental charges, filings, pledges, grants of security interests and any other form of encumbrance on the Exiting Participant’s Ownership Interest created by each such Exiting Participant.

2.1.62 Mine Reclamation Agreement means the Amended and Restated San Juan Mine Reclamation and Trust Funds Agreement, executed concurrently herewith.

2.1.63 Minimum Annual Generation (“MAG”) (expressed in MWh) means Net Maximum Capacity (“NMC”) (of Unit 3 or Unit 4, as applicable), and expressed in MW, multiplied by each Participant’s percentage Ownership Interest (“I”) in a Unit multiplied by 0.85 multiplied by (the Unit 3 Equivalent Availability Factor (“EAF”) for SCPPA and Tri-State or the Unit 4 EAF for M-S-R and Anaheim) multiplied by the total annual hours in the calendar year (“AH”). The AH in calendar year 2016 equals 8784 hours and the AH in calendar year 2017 equals 8760 hours. The foregoing is expressed in the following formula:

2.1.64 Minimum Annual Tonnage Purchase Obligation (“MTO”) means Minimum Annual Generation multiplied by the Participant’s respective actual average net unit heat rate (“NUHR”), expressed in Btu/kWh, for the year, divided by two times the weighted average heat content (“HC”), expressed in Btu/Lb, of coal delivered by SJCC in the year. The foregoing is expressed in the following formula:

2.1.65 Minimum Credit Threshold means an investment grade Credit Rating of both Baa3 from Moody’s and BBB- from S&P.

2.1.66 Moody’s means Moody’s Investors Services, Inc. or its successors.

2.1.67 Net Maximum Capacity means the maximum continuous ability of each Unit to produce power, as defined by the North American Electric Reliability Corporation in its Generating Availability Data System Data Reporting Instructions.

2.1.68 NMED means the New Mexico Environment Department or its successor agency.

2.1.69 NMPRC means the New Mexico Public Regulation Commission or its successor agency.

2.1.70 Notice of Dispute has the meaning provided for in Section 23.1.1.

2.1.71 Noticing Party has the meaning provided for in Section 23.1.1.

2.1.72 Operating Agent means the Participant or other entity which has been selected by the Participants as the entity responsible for the operation and maintenance of the Project pursuant to the SJPPA; as of the Effective Date, PNM is the Operating Agent.

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Unless otherwise specifically provided for, when in this Restructuring Agreement a reference is made to the “agent” of a Party, such reference will not be deemed to include reference to the Operating Agent.

2.1.73 Operating Insurance means policies of insurance secured or to be secured by the Operating Agent as provided for in the SJPPA.

2.1.74 Operating Work means engineering, contract preparation and administration, purchasing, repair, supervision, training, expediting, inspection, testing, protection, operation, use, management, replacement, retirement, reconstruction and maintenance of and for the benefit of the Project, including the administration of the SJPPA, environmental compliance activities and the procurement of fuel and water and other necessary materials and supplies.

2.1.75 Operation and Maintenance (“O&M”) Expenses means expenses incurred by the Operating Agent in the performance of Operating Work and chargeable to the Parties pursuant to the SJPPA and this Restructuring Agreement.

2.1.76 Other Project Agreements means agreements entered into between or among one or more of the Parties and/or other persons prior to the Execution Date in connection with the Parties’ respective purchases of Ownership Interests in the Project or the operation of the Project; the Other Project Agreements that have been identified by the Parties are listed in Exhibit B .

2.1.77 Ownership Interest means a Party’s percentage undivided ownership interest in a Unit and in common equipment and facilities and as increased, decreased, acquired or transferred as provided in this Restructuring Agreement, and rights incidental thereto.

2.1.78 Parental Guaranty has the meaning provided for in Section 3.2.1.

2.1.79 Participant means any one of PNM, TEP, Farmington, M-S-R, Los Alamos, SCPPA, Anaheim, UAMPS or Tri-State.

2.1.80 Participant Coal Consumption means each Participant’s total San Juan Project coal consumption in tons as determined by the Operating Agent. A Participant’s Coal Consumption is comprised of its share of coal consumed in its Unit(s) plus its share of coal consumed for common loads, auxiliary loads and start-up for all Units.

2.1.81 Party means any one of the Participants as well as PNMR-D.

2.1.82 Penalty Interest means interest awarded by the arbitrators pursuant to Section 23.8.

2.1.83 PNMR means PNM Resources, Inc., a New Mexico corporation.

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2.1.84 Predecessor means any person, including a Party, that, at any time prior to the Execution Date, held ownership of the Ownership Interest of a Party that is seeking indemnity or contribution for environmental Liability under Sections 19 or 20.

2.1.85 Pre-existing Stockpile Coal means coal that as of the Effective Date is stockpiled on SJCC property.

2.1.86 Project has the meaning described in Recital A.

2.1.87 Project Coal Inventory means the sum of coal in coal storage piles, silos, conveying systems, hoppers and all other coal storage at the Project as accounted in FERC Account 151.

2.1.88 Protest has the meaning provided for in Section 23.1.2.

2.1.89 Protesting Party means a Party making a protest in accordance with Section 23.1.2.1.

2.1.90 Rating Agency means Moody’s or S&P.

2.1.91 Refined Coal Supply Agreement means the Refined Coal Supply Agreement by and between San Juan Fuels, LLC and PNM dated June 21, 2013.

2.1.92 Regulatory Approval means an authorization, consent, license, certificate, permit, waiver, privilege, acceptance or approval issued or granted by a Governmental Authority. Regulatory Approvals identified by the Parties as required in connection with this Restructuring Agreement are set out in Exhibit A .

2.1.93 Regulatory Revision has the meaning provided for in Section 1.4.1.

2.1.94 Remaining Participants means those Parties that will continue participation, or acquire an Ownership Interest, in the Project on and after the Exit Date; the Remaining Participants are PNM, TEP, Farmington, UAMPS, Los Alamos and PNMR-D.

2.1.95 Restructuring Agreement has the meaning provided for in the introductory paragraph of this agreement.

2.1.96 RH SIP has the meaning provided for in Recital G.

2.1.97 RSA means the new Reclamation Services Agreement entered into between PNM and SJCC with an anticipated effective date of January 1, 2016.

2.1.98 SCR means selective catalytic reduction.

2.1.99 SJCC means San Juan Coal Company, a Delaware corporation, or its successors or assigns.

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2.1.100 SJCC Environmental Force Majeure has the meaning provided for in Section 12.1(C)(1) of the CSA.

2.1.101 SJGS means the San Juan Generating Station.

2.1.102 SJGS Plant Site means what are identified as Parcels A, B, D, E and F in Exhibit F .

2.1.103 SJPPA means the Amended and Restated San Juan Project Participation Agreement, dated March 23, 2006.

2.1.104 SJPPA Exit Date Amendment means the amendment to the SJPPA as provided for in Section 1.2.2.

2.1.105 SJPPA Restructuring Amendment means the amendment to the SJPPA as provided for in Section 1.2.1.

2.1.106 SNCR means selective non-catalytic reduction.

2.1.107 S&P means the Standard & Poor’s Financial Services, LLC (a subsidiary of McGraw-Hill Companies) or its successor.

2.1.108 Termination Date has the meaning provided for in Section 1.7.

2.1.109 Tier 1 Tonnage Allocation means a schedule allocating Tier 1 Tons on a monthly basis based on the SJGS monthly planned coal consumption.

2.1.110 Tier 1 Tons means, with respect to: (i) each of 2016 and 2017, 5.750 million tons; (ii) each of 2018 and 2019, 2.8 million tons; (iii) each of 2020 and 2021, 2.65 million tons; and (iii) 2022, 1.4 million tons.

2.1.111 Tier 2 Tons means all tons delivered to and accepted by SJGS in a year in excess of Tier 1 Tons.

2.1.112 UG-CSA means the Underground Coal Sales Agreement between PNM, TEP and SJCC executed on August 31, 2001.

2.1.113 UG-CSA Termination Agreement means the Underground Coal Sales Agreement Termination and Mutual Release Agreement among PNM, TEP, SJCC and BHP Billiton New Mexico Coal.

2.1.114 Uncontrollable Forces has the meaning provided for in Section 25.10.

2.1.115 Unit means Unit 1, Unit 2, Unit 3 or Unit 4 of the Project.

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2.1.116 Willful Action means: (i) action taken or not taken by a Party (or the Operating Agent), at the direction of its directors, members of its Board, officers or employees having management or administrative responsibility affecting its performance under this Restructuring Agreement, which action is knowingly or intentionally taken or not taken with conscious indifference to the consequences thereof or with intent that injury or damage would probably result therefrom; or (ii) action taken or not taken by a Party (or the Operating Agent) at the direction of its directors, members of its Board, officers or employees having management or administrative responsibility affecting its performance hereunder, which action has been determined by final arbitration award or final judgment or judicial decree to be a material default hereunder and which action occurs or continues beyond the time specified in such arbitration award or judgment or judicial decree for curing such default, or if no time to cure is specified therein, occurs or continues beyond a reasonable time to cure such default; or (iii) action taken or not taken by a Party (or the Operating Agent), at the direction of its directors, members of its Board, officers or employees having management or administrative responsibility affecting its performance hereunder, which action is knowingly or intentionally taken or not taken with the knowledge that such action taken or not taken is a material default hereunder. The phrase “employees having management or administrative responsibility,” as used in this Section 2.1.116, means employees of a Party who are responsible for one or more of the executive functions of planning, organizing, coordinating, directing, controlling and supervising such Party’s performance under this Restructuring Agreement; provided, however, that, with respect to employees of the Operating Agent acting in its capacity as such and not in its capacity as a Party, but only during such time as any one of Unit 1, 2, 3 or 4 is commercially producing electrical power, such phrase refers only to: (x) the senior employee of the Operating Agent on duty at the Project who is responsible for the operation of the Units, and (y) anyone in the organizational structure of the Operating Agent between such senior employee and an officer. After such time as none of Unit 1, 2, 3 or 4 is commercially producing electrical power, the phrase “employees having management or administrative responsibility” as used in this Section 2.1.116 will mean employees of any Party (including the Operating Agent), who are responsible for one or more of the executive functions of planning, organizing, coordinating, directing, controlling and supervising such Party’s performance under this Restructuring Agreement. Willful Action does not include any act or failure to act which is merely involuntary, accidental or negligent.

2.2 Rules of Interpretation .

Unless a clear contrary intention appears, this Restructuring Agreement will be construed and interpreted as follows:

2.2.1 Any reference to a person includes any individual, partnership, firm, company, corporation, joint venture, trust, association, organization, governmental entity or other entity;

2.2.2 Any reference to a day, week, month or year is to a calendar day, week, month or year, unless otherwise specified as a Business Day;

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2.2.3 Any act required to occur by or on a certain day is required to occur before or on that day unless the day falls on a Saturday, Sunday or federal holiday, in which case the act must occur before or on the next Business Day;

2.2.4 The singular includes the plural and vice versa ;

2.2.5 Reference to the feminine, masculine or neutral gender includes reference to all other genders;

2.2.6 Reference to any person includes such person’s successors and assigns but, in the case of a Party, only if such successors and assigns are permitted by this Restructuring Agreement;

2.2.7 Unless expressly stated otherwise, reference to any agreement (including this Restructuring Agreement), document, instrument or tariff means such agreement, document, instrument or tariff as amended, supplemented, replaced or modified and in effect from time-to-time;

2.2.8 Reference to any Law means such Law as amended, modified, codified supplemented or reenacted, in whole or in part, and in effect from time-to-time, including, if applicable, rules and regulations promulgated thereunder;

2.2.9 Unless expressly stated otherwise, reference to any article, section, exhibit or appendix means such article, section, exhibit or appendix of this Restructuring Agreement, as the case may be;

2.2.10 “Hereunder,” “hereof,” “herein,” “hereto” and words of similar import are deemed references to this Restructuring Agreement as a whole and not to any particular provision hereof;

2.2.11 “Including,” “include” and “includes” are deemed to be followed by the phrase “without limitation” and will not be construed to mean the examples given constitute an exclusive list of the matters covered;

2.2.12 Relating to the determination of any period of time, “from” means “from and including,” “to” means “to but excluding” and “through” means “through and including”; and

2.2.13 Whenever an act is required to be performed by a particular time of day, prevailing Mountain Time will be the standard by which performance is measured.

3. Status of PNMR-D under SJPPA

3.1 PNMR-D as Party to SJPPA . As reflected in this Restructuring Agreement, PNMR-D will not acquire an Ownership Interest in the Project until the Exit Date. However, the SJPPA will be amended to provide that PNMR-D will be a party to the SJPPA upon the Effective Date. The purpose of adding PNMR-D as a party to the SJPPA is to set out certain

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financial obligations PNMR-D will assume, and rights it will have, in contemplation of its acquisition of an Ownership Interest on the Exit Date as described in Sections 6.1 and 6.2.

3.2 Parental Guaranty and Letter of Credit .

3.2.1 Parental Guaranty . As a condition of PNMR-D becoming a party to the SJPPA as provided in Section 3.1, PNMR-D’s parent company, PNM Resources, Inc. (“PNMR”), will enter into, on or before the Execution Date, a parental guaranty of PNMR-D’s obligations under the Restructuring Agreement, the Decommissioning Agreement, the Mine Reclamation Agreement and the SJPPA (“Parental Guaranty”). The form of the Parental Guaranty is attached hereto as Exhibit I .

3.2.2 Letter of Credit . If PNMR’s Credit Rating falls below the Minimum Credit Threshold, then PNMR will provide the Operating Agent with a letter of credit (the “Letter of Credit”) in the amount of ten million dollars ($10,000,000) with the Operating Agent as the beneficiary. The form of the Letter of Credit is attached hereto as Exhibit J . PNMR will deliver the Letter of Credit to the Operating Agent for the benefit of the Guaranteed Parties within ten (10) Business Days following: (i) the effective date of the Credit Rating downgrade that results in PNMR not meeting the Minimum Credit Threshold; or (ii) the withdrawal of PNMR from being rated by one or more of the Rating Agencies. Upon a failure of PNMR to make payment under the Parental Guaranty or a failure of PNMR to procure a conforming replacement Letter of Credit no later than twenty (20) days before expiration of the existing Letter of Credit, the beneficiary will promptly draw upon the Letter of Credit. If appropriate, the Operating Agent will prorate among the Guaranteed Parties the funds drawn against the Letter of Credit. If the issuer of the Letter of Credit notifies the Operating Agent that the issuer’s long term obligation rating has fallen below the rating established in the Letter of Credit, PNMR will have twenty-five (25) days within which to replace the Letter of Credit with a new letter of credit from an issuer that meets the minimum long term obligation rating established in the Letter of Credit. If PNMR fails to procure a new letter of credit as provided in the previous sentence, the beneficiary will draw upon the Letter of Credit for the benefit of the Guaranteed Parties.

4. Restructuring Fee, Demand Charge and Voting

4.1 Restructuring Fee . In consideration of costs to restructure the ownership of the Project as provided for herein and for the restructuring of rights and obligations of the Parties in relation to the Project, the Exiting Participants will pay and the Remaining Participants will accept a restructuring fee in the amount of eight million eight hundred thousand dollars ($8,800,000) (“Restructuring Fee”).

4.1.1 The responsibility to pay the Restructuring Fee is allocated among the Exiting Participants in the following percentages: M-S-R – 32.22%; Anaheim – 11.48%; SCPPA – 47.08%; and Tri-State – 9.22%.

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4.1.2 The receipt of the Restructuring Fee is allocated as follows: PNM – 0%; TEP – 0%; Farmington – 17.24%; LAC – 22.20%; UAMPS – 22.20%; and PNMR-D – 38.36%.

4.2 Payment of Restructuring Fee and Common Participation Shares of Shared Coal Inventory .

Payment of the Restructuring Fee, and payment for the Common Participation Shares of Shared Coal Inventory pursuant to Section 5.3, will occur on the same date, in the manner agreed upon by the Parties, which date will be no later than thirty (30) days after the Effective Date. Each Exiting Participant will pay its proportionate share of the Restructuring Fee as set forth in Section 4.1.1 to the Remaining Participants entitled to receive such payment as provided in Section 4.1.2.

4.3 Costs of Capital Improvements Invoiced after January 1, 2015 . The provisions of Section 7 of the SJPPA, Capital Improvements and Retirements of San Juan Project and Participants’ Solely Owned Facilities, are modified by this Section 4.3 as follows:

4.3.1 The Remaining Participants are responsible for the costs of Capital Improvements invoiced after January 1, 2015, and the Exiting Participants have no ownership interest in such Capital Improvements. The Exiting Participants will have no responsibility for costs of the SNCR/balanced draft project to be placed on Units 1 and 4. Costs of Capital Improvements invoiced after January 1, 2015, are allocated to the Remaining Participants as follows:

4.3.1.1 For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:

4.3.1.1.1 PNM: 64.482%

4.3.1.1.2 Farmington: 8.475%

4.3.1.1.3 LAC: 7.200%

4.3.1.1.4 UAMPS: 7.028%

4.3.1.1.5 PNMR-D 12.815%

4.3.1.2 For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:

4.3.1.2.1 PNM: 64.482%

4.3.1.2.2 Farmington: 8.475%

4.3.1.2.3 LAC: 7.200%

4.3.1.2.4 UAMPS: 7.028%

4.3.1.2.5 PNMR-D 12.815%

4.3.1.3 For equipment and facilities common to all of the Units in accordance with the following percentages:

4.3.1.3.1 PNM: 58.671%

4.3.1.3.2 TEP: 20.068%

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4.3.1.3.3 Farmington: 5.076%

4.3.1.3.4 LAC: 4.309%

4.3.1.3.5 UAMPS: 4.203%

4.3.1.3.6 PNMR-D: 7.673%

4.3.2 The modifications to Section 7 of the SJPPA set out in Section 4.3.1 replace and supersede the provisions of Section 7.13 of the SJPPA accepted for filing as PNM Rate Schedule No. 144 and currently on file with the FERC.

4.4 Demand Charge . For the period July 1, 2014, through December 31, 2017, the Exiting Participants will pay a Demand Charge for the use of new Capital Improvements implemented on Unit 4, facilities common to Units 3 and 4, and facilities common to all Units.

4.4.1 The total Demand Charge is six million two hundred thousand dollars ($6,200,000) of which five million three hundred fourteen thousand two hundred eighty-six dollars ($5,314,286) remains unpaid. The Demand Charge will be paid regardless of the output of Unit 3 or 4. The Exiting Participants will be invoiced by the Operating Agent for and will pay the unpaid balance of the Demand Charge in monthly amounts of no less than 1/36 ^th of the unpaid balance; provided, the sum of the monthly amounts which would have accrued between January 1, 2015 and the Effective Date will be paid within forty-five (45) days of the Effective Date.

4.4.2 The Exiting Participants will pay the Demand Charge as follows:

4.4.2.1 M-S-R 71.650%

4.4.2.2 Anaheim 25.000%

4.4.2.3 SCPPA 2.800%

4.4.2.4 Tri-State 0.550%

4.4.3 The Remaining Participants will be paid the Demand Charge as follows from July 1, 2014 through December 31, 2014:


4.4.3.1	PNM 0.000%


4.4.3.2	TEP 0.000%


4.4.3.3	Farmington 55.600%


4.4.3.4	LAC 22.200%


4.4.3.5	UAMPS 22.200%


4.4.3.6	PNMR-D 0.000%

4.4.4 The Remaining Participants will be paid the Demand Charge as follows from January 1, 2015 through December 31, 2017:

4.4.4.1 PNM 0.000%

4.4.4.2 TEP 0.000%

4.4.4.3 Farmington 17.24%

4.4.4.4 LAC 22.20%

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4.4.4.5 UAMPS 22.20%

4.4.4.6 PNMR-D 38.36%

4.4.5 With respect to any Demand Charges paid or received between July 1, 2014 and December 31, 2014, any Exiting Participant that made such a Demand Charge payment and any Remaining Participant that received a Demand Charge payment and did not return it will be credited the amount of that payment or receipt as follows: the amount of any such payment will be proportionately offset against the amount of the Demand Charge payment each such Exiting Participant is obligated to pay under Sections 4.4.1 through 4.4.4, and the amount of any such receipt by a Remaining Participant will be proportionately offset against the amount of the Demand Charge payment each such Remaining Participant is entitled to receive under Sections 4.4.1 through 4.4.4. The Demand Charge payments made by Exiting Participants to the Operating Agent between July 1, 2014, and December 31, 2014, were as follows: M-S-R - $634,614; Anaheim - $221,429; SCPPA - $24,800; and Tri-State - $4,871. The Demand Charge payments received by the Remaining Participants between July 1, 2014, and December 31, 2014, and not returned to the Operating Agent were as follows: Farmington - $492,457. For a Remaining Participant that returned Demand Charge payments received between July 1, 2014 and December 31, 2014, such Remaining Participant will receive a disbursement from the Operating Agent constituting the Remaining Participant’s entire proportionate share of Demand Charge payments as set forth in Sections 4.4.1, 4.4.3 and 4.4.4.

4.5 Voting on Capital Improvements . As of the Effective Date, for purposes of the application of the double voting procedures set out in Section 18.4 of the SJPPA, the Ownership Interests and the number of individual Parties required to approve a Capital Improvement will be as provided in Section 4.3.1.

5. Fuel Supply


5.1	Certain Cost Allocations . Payment obligations for coal supply, reclamation and CCR disposal will be allocated as follows:

5.1.1 For payments under the UG-CSA, the CCBDA, the UG-CSA Termination Agreement and the CCBDA Termination Agreement, Sections 23.1 through 23.13 of the SJPPA (as those sections were in effect on March 23, 2006) will apply.

5.1.2 Sections 23.1 through 23.13 of the SJPPA (as those sections were in effect on March 23, 2006) will apply for allocation of any fuel-related payments (other than for coal) incurred through December 31, 2017 and chargeable to FERC Account 501, including limestone, fuel oil, CCR disposal, fuel handling or start-up or auxiliary power and energy.

5.1.3 For payments arising under the CSA and the CCRDA, Sections 5.2 through 5.7 of this Restructuring Agreement will apply.

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5.1.4 Payments arising under the RSA will be allocated as determined under the Mine Reclamation Agreement.

5.2

Supply of Coal to Exiting Participants and Remaining Participants . Beginning on January 1, 2016, PNM will supply coal to (i) the Exiting Participants under the provisions of Sections 5.3 through 5.6; and (ii) the Remaining Participants under the provisions of Section 5.7. PNM will have all cost obligations under the CSA for coal supplied to the Exiting Participants and PNM will have all rights to the Exiting Participants’ inventory relinquished to PNM under Section 5.3.

5.3

Relinquishment of Coal Inventory . The Exiting Participants will relinquish to PNM their Common Participation Shares of Shared Coal Inventory that exist as of January 1, 2016, at the following values: (i) $16.88/ton for coal tons stockpiled on SJCC’s property and $22.69/ton for coal tons stockpiled on the SJGS Plant Site. The total sum paid by PNM for Common Participation Shares of Shared Coal Inventory will be allocated as follows:


5.3.1	M-S-R 32.22%


5.3.2	Anaheim 11.48%


5.3.3	SCPPA 47.08%


5.3.4	Tri-State 9.22%

5.4

Coal Supply for Exiting Participants . From January 1, 2016 through the Exit Date, the Exiting Participants will receive coal monthly to meet their Participant Coal Consumption from PNM at a cost of $50/ton in 2016 and 2017. This $50/ton covers all payment obligations for coal supplied to the Exiting Participants that might otherwise be due under (i) this Restructuring Agreement; (ii) the CSA, including Legacy Costs, taxes and royalties; and (iii) gross receipts taxes under the Refined Coal Supply Agreement or otherwise. This $50/ton does not include payments for reclamation costs under the RSA or disposal costs under the CCRDA.


5.5	Minimum Purchase Obligations . The Exiting Participants will not have any take-or-pay or minimum purchase obligations under the CSA; provided, however, the Exiting Participants must comply with the dispatch requirements described in Section 5.6.

5.6

Exiting Participant Dispatch Requirements; Invoicing . The Exiting Participants will dispatch their respective shares of the Units to no less than their Minimum Annual Generation. The Exiting Participants will be billed monthly based on their Participant Coal Consumption. At the end of each of 2016 and 2017, any Exiting Participant that has not met its Minimum Annual Tonnage Purchase Obligation will be billed at $50/ton for the difference between its actual Participant Coal Consumption and its Minimum Annual Tonnage Purchase Obligation; provided, in the event that at any time during 2016 or 2017 PNM is unable to supply coal to the Exiting Participants as provided in Section 5.4, then the Minimum Annual Tonnage Purchase Obligation will be proportionately reduced to account for any such period of time in which PNM is unable to supply coal.


5.7	Monthly Remaining Participant Coal Invoicing . For purposes of the calculations in this Section 5.7, PNM’s Common Participation Share will include the Exiting Participants’

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Common Participation Share, and PNM’s Participant Coal Consumption will include the Exiting Participants’ Participant Coal Consumption. SJCC will invoice PNM monthly as provided under the CSA. PNM will invoice each Remaining Participant monthly by Coal Tonnage Component and such Coal Tonnage Component will be paid for as follows:

5.7.1 Pre-existing Stockpile Coal Tons . Pre-existing Stockpile Coal tons as invoiced by SJCC will be allocated by a Remaining Participant’s Common Participation Share as of the Effective Date and will be paid for by each Remaining Participant at the price per ton charged by SJCC in its monthly invoicing to PNM.

5.7.2 Tier 1 Tons . Each year, PNM will develop a monthly Tier 1 Tonnage Allocation schedule with SJCC in the annual operating plan process as provided for in Section 7.2 of the CSA. With input from the Remaining Participants, PNM will develop a monthly allocation by Remaining Participant of such Tier 1 Tons (such individual allocation, its “Tier 1 Tonnage Allocation”). Such monthly Tier 1 Tonnage Allocation will be paid for by Remaining Participants whether or not their Participant Coal Consumption exceeded their Tier 1 Tonnage Allocation in the month. Monthly, for each Remaining Participant, its Tier 1 Tonnage Allocation, net of its invoiced Pre-existing Stockpile Coal for such month will be paid for at the then-existing price for Tier 1 Tons under the CSA. In each of 2016 and 2017, five million six hundred thousand (5,600,000) tons will be allocated by Remaining Participant Share, and then PNM will be allocated an additional one hundred fifty thousand (150,000) tons in each of those years. In each of 2018 and 2019, two million eight hundred thousand (2,800,000) tons will be allocated by Remaining Participant Share. In each of 2020 and 2021, two million eight hundred thousand (2,800,000) tons will be allocated by Remaining Participant Share, and then PNM’s allocation will be reduced by one hundred fifty thousand (150,000) tons in each of those years. In 2022, one million four hundred thousand (1,400,000) tons will be allocated by Remaining Participant Share.

5.7.3 Tier 2 Tons . To the extent that a Remaining Participant’s Participant Coal Consumption in a month exceeds its Tier 1 Tonnage Allocation for such month, PNM will invoice such Remaining Participant such excess as Tier 2 Tons to be paid for at the then existing price for Tier 2 Tons under the CSA.

5.7.4 Legacy Costs . Legacy Costs as invoiced monthly by SJCC will be allocated using a Remaining Participant’s Common Participation Share for that year.

5.7.5 Reclamation Bond Premium . Cost for SJCC’s reclamation bond premium invoiced through the CSA will be allocated using a Remaining Participant’s Common Participation Share for that year.

5.7.6 Weight-based Taxes . Weight-based taxes will be applied to the tonnages as invoiced by PNM to each Remaining Participant at the then-existing rates applicable to SJCC invoices.

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5.7.7 Revenue-based Taxes and Royalties . Revenue-based taxes and royalties will be applied to the tonnages and total coal costs as invoiced by PNM to each Remaining Participant at the then-existing rates applicable to SJCC invoices.

5.7.8 SJCC Environmental Force Majeure . In the event of an SJCC Environmental Force Majeure, then Available Pre-existing Stockpile Tons will be allocated in the same manner as Pre-existing Stockpile Coal tons, and Force Majeure Tons will be allocated in the same manner as Tier 1 Tons unless otherwise approved by the Remaining Participants in the Fuels Committee. Such calculations will be on an annual basis.

5.7.9 Other Costs . Any other costs billed by SJCC under the CSA and not specifically addressed in this Section 5.7 will be apportioned among and paid for by the Remaining Participants on the basis of Remaining Participant’s Common Participation Share for that year unless otherwise annually approved by the Remaining Participants in the Fuels Committee.

5.7.10 Annual Year-End Reconciliation Process .

5.7.10.1 At the end of each year, the Operating Agent will reconcile the sum of each Remaining Participant’s monthly CSA-related payments to a properly allocable share of annual Tier 1 Tons, Tier 2 Tons, Pre-existing Stockpile Coal tons, and cost associated with any change in Project Coal Inventory and invoice or refund any such reconciliation amounts to each Remaining Participant.

5.7.10.2 Any net consumption of Project Coal Inventory tons will be charged to FERC Account 501 and apportioned among and paid for by the Remaining Participants on the basis of the percentage that each Remaining Participant’s annual Tier 2 Tons after the reconciliation process bears to the total annual Tier 2 Tons consumption after the reconciliation process for all Units. The price for such tons will be determined by dividing the total recorded cost in FERC Account 151 by the total number of tons of coal in Project Coal Inventory, both as recorded on January 1 of said year. The total amount of any such payment for consumed Project Coal Inventory tons will subsequently be credited to FERC Account 151 and apportioned to the Remaining Participants based on the Remaining Participant’s Common Participation Share for that year.

5.7.10.3 The costs of any net addition to Project Coal Inventory tons, as invoiced by SJCC, will be charged to FERC Account 151 and apportioned to and paid for by the Remaining Participants based on the Remaining Participant’s Common Participation Share for that year.

5.7.10.4 If, at the end of any year, the Operating Agent has collected amounts in excess of those due SJCC under the CSA, such over-collection will be refunded to the Remaining Participants. The refund to each Remaining Participant will be an amount equal to the total amount of the over-collection multiplied by

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the tons each Remaining Participant’s Coal Consumption was less than its total annual Tier 1 Tonnage Allocation divided by the total amount by which all such Remaining Participants’ Coal Consumption was less than their Tier 1 Tonnage Allocation.


5.8	Section 23.14 Superseded . The provisions of this Section 5 replace and supersede the provisions of Section 23.14 of the SJPPA accepted for filing as PNM Rate Schedule No. 144 and currently on file with the FERC.

6. Exit Date and Ownership Conveyances

6.1 Transfer of Exiting Participants’ Rights . The Exiting Participants will each transfer all of their respective rights, titles and interests in and to their Ownership Interests to the Acquiring Participants as specified in Section 6.2 and terminate their active involvement in the operation of SJGS on the Exit Date, except as expressly provided for in this Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement. The Remaining Participants will purchase fuel oil inventory from the Exiting Participants at book value on the Exit Date. On the first monthly invoice following the Exit Date, the Operating Agent will credit each of the Exiting Participants for its share of the book value for fuel oil inventory, and charge each of the Remaining Participants for its share of such book value. Each Exiting Participant’s share of fuel oil inventory will be calculated using its Common Participation Share prior to the Exit Date. Each Remaining Participant’s share will be calculated using its Common Participation Share after the Exit Date.

6.2 Acquisition of Ownership Interests of Exiting Participants . On the Exit Date and in accordance with this Restructuring Agreement and with all other instruments referenced herein:

6.2.1 SCPPA and Tri-State will convey all of their respective rights, titles and interests in and to their Ownership Interests to PNM, and PNM (an “Acquiring Participant”) will acquire all of SCPPA’s and Tri-State’s respective rights, titles and interests in and to their Ownership Interests; and

6.2.2 M-S-R and Anaheim will convey all of their respective rights, titles and interests in and to their Ownership Interests to PNM and PNMR-D, and PNM and PNMR-D (“Acquiring Participants”) will acquire all of M-S-R’s and Anaheim’s respective rights, titles and interests in and to their Ownership Interests, including approximately 132 MW of Unit 4 in the case of PNM (an additional 26.025% ownership of Unit 4) and approximately 65 MW of Unit 4 in the case of PNMR-D (a 12.815% ownership of Unit 4).

6.2.3 TEP, Los Alamos, Farmington and UAMPS will not acquire any ownership of Unit 3 or any additional Ownership Interest in Unit 4; and PNMR-D will not acquire any ownership of Unit 3, but all Remaining Participants will have shares of plant common and Unit 3 and 4 common as set forth in Section 6.3.

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6.3 Plant Ownership after Acquisition of Ownership Interests of Exiting Participants .

Upon completion of the transfers provided for in Section 6.2, the Remaining Participants will hold the following Ownership Interests in Units 3 and 4, Unit 3 and 4 common and in plant common equipment and facilities, which change in Ownership Interests will be reflected in the SJPPA Exit Date Amendment:



	Unit 3		Unit 4		Unit 3&4 Common		Plant Common
PNM	100.00	%	64.482	%	64.482	%	58.671	%
PNMR-D	0.000	%	12.815	%	12.815	%	7.673	%
TEP	0.000	%	0.000	%	0.000	%	20.068	%
Farmington	0.000	%	8.475	%	8.475	%	5.076	%
LAC	0.000	%	7.200	%	7.200	%	4.309	%
UAMPS	0.000	%	7.028	%	7.028	%	4.203	%
Exiting Participants	0.000	%	0.000	%	0.000	%	0.000	%
Total	100.00	%	100.000	%	100.000	%	100.000	%

6.4 Unit 1 and Unit 2 Ownerships After Exit Date . This Restructuring Agreement does not alter the ownership of Units 1 and 2. After the Exit Date, Units 1 and 2 will continue to be owned 50% by PNM and 50% by TEP.

6.5 “AS IS” Conveyances . Except as otherwise provided in this Restructuring Agreement: (i) THE TRANSFERS PROVIDED FOR IN THIS SECTION 6 ARE TO BE ON AN “AS IS,” “WHERE IS” AND “WITH ALL FAULTS” BASIS; (ii) NO EXITING PARTICIPANT MAKES ANY REPRESENTATION OR WARRANTY WHATSOEVER, EXPRESS, IMPLIED OR STATUTORY, INCLUDING WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY AS TO THE VALUE, QUANTITY, CONDITION, SALABILITY, OBSOLESCENCE, MERCHANTABILITY, FITNESS OR SUITABILITY FOR USE OR WORKING ORDER OF, ALL OR ANY PART OF THE OWNERSHIP INTERESTS TO BE TRANSFERRED HEREUNDER OR AS TO ANY PORTION OF THE PROJECT; AND (iii) NO EXITING PARTICIPANT REPRESENTS OR WARRANTS THAT THE USE OR OPERATION OF AN OWNERSHIP INTEREST OR ANY PORTION OF THE PROJECT WILL NOT VIOLATE OR CONFLICT WITH ANY PATENT, TRADEMARK OR SERVICE MARK RIGHTS OF ANY THIRD PARTY. EACH ACQUIRING PARTICIPANT ACCEPTS ALL SUCH TRANSFERS IN ACCORDANCE WITH THE TERMS AND CONDITIONS OF THIS RESTRUCTURING AGREEMENT.

7. Closing of Ownership Conveyances

7.1 Closing . The date of Closing of the conveyances provided for in Section 6.2 (“Closing Date”) will take place on or before the Exit Date at a time and place agreeable to the Exiting Participants and the Acquiring Participants, will be effective as of the Exit Date and may occur via the exchange of electronically transmitted signatures contained in counterpart signature pages for any required Closing documents. Closing will occur after all conditions to Closing set

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forth in this Restructuring Agreement (other than actions to be taken or items to be delivered at Closing) have been satisfied or waived.

7.2 Closing Statement . At least sixty (60) days prior to the anticipated Closing Date, the Exiting Participants and the Acquiring Participants will have jointly prepared a preliminary closing statement setting out relevant details concerning the Closing and relevant post-Closing items; and at least seven (7) days prior to the anticipated Closing Date, the Exiting Participants and the Acquiring Participants will have jointly prepared a final closing statement (“Closing Statement”). Copies of the preliminary closing statement and the Closing Statement will be provided to all of the Parties.

7.3 Closing Deliveries by the Exiting Participants . At the Closing, the Exiting Participants will deliver, or will cause to be delivered, to the Acquiring Participants, each of the following:

7.3.1 Instruments of Sale and Conveyance in substantially the form of Exhibit C , duly executed by the Exiting Participants.

7.3.2 Evidence, in form and substance reasonably satisfactory to the Acquiring Participants and their counsel, of the Exiting Participants’ receipt of: (i) Board approvals authorizing the conveyance of the Exiting Participants’ Ownership Interests in SJGS to the Acquiring Participants; (ii) any required Regulatory Approvals; and (iii) the release of all Liens and Encumbrances (exclusive of taxes and charges that are prorated as of the Exit Date).

7.3.3 A certificate by each Exiting Participant, duly executed by an authorized officer or agent of the Exiting Participant, identifying the name and title and bearing the signatures of the representatives of each Exiting Participant authorized to execute and deliver documents at the Closing.

7.3.4 A bring-down opinion by each Exiting Participant’s counsel, in form and substance reasonably acceptable to the Acquiring Participants and their counsel, in the form set forth in Exhibit K .

7.3.5 As provided in Section 12.2, an appropriate instrument in the form of Exhibit G , relinquishing their easements and license rights in lands associated with the Project.

7.3.6 All such other agreements, documents, instruments and writings required by the Acquiring Participants to be delivered at or prior to the Closing Date pursuant to this Restructuring Agreement or necessary to sell, assign, convey, transfer and deliver all of the Exiting Participants’ rights, titles and interests in and to Ownership Interests to be transferred pursuant to and in accordance with this Restructuring Agreement and, where necessary and desirable, in recordable form.

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7.4 Closing Deliveries by the Acquiring Participants . At the Closing, the Acquiring Participants will deliver, or will cause to be delivered, to the Exiting Participants, each of the following:

7.4.1 Evidence, in form and substance reasonably satisfactory to the Exiting Participants and their counsel, of the Acquiring Participants’ receipt of: (i) Board approvals authorizing the acquisition of the Exiting Participants’ Ownership Interests in SJGS; and (ii) any required Regulatory Approvals.

7.4.2 A certificate by each Acquiring Participant, duly executed by an authorized officer or agent of the Acquiring Participant, identifying the name and title and bearing the signatures of the representatives of each Acquiring Participant authorized to execute and deliver documents at the Closing.

7.4.3 A bring-down opinion by each Acquiring Participant’s counsel, in form and substance reasonably acceptable to the Exiting Participants and their counsel, in the form set forth in Exhibit K .

7.4.4 An instrument as described in Section 12.3, the form of which is shown in Exhibit H , by which PNM and TEP provide to the Exiting Participants all access and use rights necessary to exercise their rights, protect their interests and fulfill their obligations under this Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement.

7.4.5 All such other agreements, documents, instruments and writings required by the Exiting Participants to be delivered at or prior to the Closing Date pursuant to this Restructuring Agreement or necessary to acquire, accept, own and operate all of the Acquiring Participants’ rights, titles and interests to be acquired pursuant to and in accordance with this Restructuring Agreement and, where necessary and desirable, in recordable form.

7.5 Conditions Precedent . The obligations of the Exiting Participants to complete the Closing are subject to the satisfaction or waiver, on or prior to the Closing Date, of each of the following conditions precedent by the Acquiring Participants (each a “Condition Precedent”); and the obligations of the Acquiring Participants to complete the Closing are subject to the satisfaction or waiver, on or prior to the Closing Date, of each of the following Conditions Precedent by the Exiting Participants. To the extent any Condition Precedent has not been satisfied or waived, the Party required to satisfy the condition will take prompt steps to do so.

7.5.1 All Acquiring Participants and Exiting Participants have performed or complied in all material respects with all covenants, agreements and conditions contained in this Restructuring Agreement, the Mine Reclamation Agreement and the SJPPA.

7.5.2 All Acquiring Participants and Exiting Participants have received Regulatory Approvals required for the Closing to occur.

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7.5.3 The representations and warranties of the Acquiring Participants and Exiting Participants set forth in Section 17 are true and correct in all material respects as of the Closing Date, in each case as though made as of the Closing Date.

7.5.4 All consents or approvals to the Closing that may be required from any lender or creditor of an Acquiring Participant or an Exiting Participant have been obtained and all requirements related to the Closing have been satisfied in respect of master indentures or other financing instruments or arrangements to which such Acquiring Participant or Exiting Participant may be parties.

7.6 Prior Notification of Certain Events . No later than ninety (90) days prior to the scheduled or anticipated Closing Date, if as a result of uncertainties resulting from pending judicial or regulatory proceedings, a Party is uncertain of its ability to satisfy the conditions for Closing as referenced in Sections 7.3, 7.4 or 7.5, such Party will provide written notice to the other Parties of such uncertainty. Upon receipt of any notification given pursuant to this Section 7.6, the Parties will confer in good faith regarding the circumstances set out in the notification and will attempt, within seventy-five (75) days of receipt of the notification, or such other period as the Parties may determine, to mutually agree upon the appropriate course of action in light of the notification, including negotiating a layoff agreement with Unit 4 Exiting Participants, such layoff agreement to be effective between January 1, 2018, and the Closing Date or the expiration of the SJPPA, whichever occurs first.

7.7 Prorations . Except as may otherwise be provided in this Restructuring Agreement, all of the ordinary and recurring items normally charged to the Participants, including property taxes, insurance premiums and O&M Expenses in any period prior to the Exit Date relating to the operation of the Project, as provided for in the SJPPA, will be prorated and charged as of the Exit Date. All Parties will be liable for their prorated share of such expenses to the extent such items relate to all time periods prior to the Exit Date and the Remaining Participants will be liable to the extent such items relate to all time periods on and after the Exit Date.

7.8 Governmental Recording and Filing . To the extent required, and as addressed in the Closing Statement, the Exiting Participants and the Acquiring Participants will cause appropriate releases, terminations, conveyances, deeds and other instruments reflecting the transfers provided for in Section 6 to be filed in a timely manner in the real estate records of San Juan County, New Mexico and/or in the offices of other appropriate Governmental Authorities.

8. Notifications, Consents and Rights-of-First-Refusal. To effectuate the transfers provided for in Section 6, all Parties hereby expressly: (i) give any and all prior notifications and grant any and all required consents that they have or may have a right to give or grant under the SJPPA (including under Section 10 of the SJPPA) or under any other agreements; and (ii) waive, relinquish or decline to exercise, any rights they have or may have under Section 11 of the SJPPA or under any other agreements with respect to the exercise of any right-of-first-refusal in connection with the transfers provided for in Section 6.

9. Operation and Maintenance Expenses. Through December 31, 2017, the Exiting Participants will continue to pay all O&M Expenses associated with their Ownership

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Interests in accordance with Section 28 of the SJPPA and will have no responsibility for ongoing O&M work thereafter, except as required by Section 19.

10. Replacement Power. Each Participant will be solely responsible for its own replacement power requirements resulting from: (i) in the case of the Exiting Participants, the Exiting Participant’s exit from active involvement in the operation of SJGS; or (ii) in the case of all affected Participants, the retirement of Unit 2 or Unit 3.

11. Other Project Agreements

11.1 Other Project Agreements Identified . The Other Project Agreements are shown in Exhibit B .

11.2 Actions with Respect to Other Project Agreements . Each Party will undertake an analysis of those Other Project Agreements to which it is a party and will address with each counterparty to each Other Project Agreement whether such Other Project Agreement should be retained, amended, terminated or superseded. The affected Parties that are parties to Other Project Agreements will act in a timely fashion prior to the Exit Date to execute any requisite instruments to amend, terminate or supersede such Other Project Agreements and to seek and obtain any requisite Regulatory Approvals in regard thereto.

12. Land Ownership

12.1 No Change in Ownership . Nothing in this Restructuring Agreement will be construed to effect a change of ownership interests in real property, as provided in Section 6.1 of the SJPPA, except as may be provided in Sections 7.3.5, 7.4.4, 12.2 and 12.3 of this Restructuring Agreement.

12.2 Relinquishment of Certain Rights . Upon the transfer of Ownership Interests on the Exit Date, the Exiting Participants will deliver appropriate instruments in the form of Exhibit G relinquishing their easements and license rights in lands associated with the Project, as provided in Section 7.3.5.

12.3 Easement and Right of Entry . Upon the transfer of the Ownership Interests on the Exit Date, PNM and TEP will deliver an instrument in the form of Exhibit H to each of the Exiting Participants providing them all access and use rights necessary to exercise their rights, protect their interests and fulfill their obligations under this Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement, as provided in Section 7.4.3.

13. Coal Mine Reclamation Funding. The arrangements under which mine reclamation will be undertaken, and the Parties’ agreed funding responsibilities for mine reclamation, will be as provided in the Mine Reclamation Agreement.

14. Decommissioning. The arrangements under which Project decommissioning will be undertaken, and the Parties’ agreed funding responsibilities for decommissioning, will be as

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provided in the Decommissioning Agreement, and such agreement will become effective as of the Exit Date.

15. Confidentiality

15.1 Confidentiality of Negotiations . The Parties’ discussions and negotiations that led to the development of this Restructuring Agreement, the Decommissioning Agreement, the Mine Reclamation Agreement, the SJPPA Restructuring Amendment and the SJPPA Exit Date Amendment, including discussions taking place in the context of mediation, were conducted in confidence and will remain confidential; provided, that nothing herein will prevent a Party from making disclosures pursuant to a requirement of Law (including laws related to the inspection of public records and securities), including subpoena or discovery request. If any Party determines that it is legally obligated to make a disclosure, the Party obligated to make such disclosure will make reasonable efforts to notify the other Parties prior to such disclosure and will reasonably cooperate with any other Party in seeking an order of a Governmental Authority preventing or limiting such disclosure; provided further, however, that the Party seeking any such order to prevent or limit disclosure will be responsible for all costs for seeking such an order. Prior to making disclosure, a Party will, as available or appropriate, attempt to utilize a confidentiality agreement to protect the confidentiality of the information disclosed.

15.2 Non-confidentiality of Restructuring Agreement . While negotiations were and remain confidential as addressed in Section 15.1, neither this Restructuring Agreement nor any version of it publicly disclosed pursuant to applicable Law is confidential.

16. Taxes

16.1 Obligations of Parties . All taxes or assessments levied against each Party’s Ownership Interest, excepting those taxes or assessments levied against an individual Party on behalf of other Parties, will be the sole responsibility of the Party upon whom said taxes and assessments are levied, subject to proration as set forth in Section 7.7. If any taxes or assessments are levied and assessed in a manner other than specified in this Section 16.1, it will be the responsibility of the Parties to establish equitable standard practices and procedures for the apportionment among the Parties of such taxes and assessments and the payment thereof.

16.2 Notification of Taxing Authorities . In conjunction with the Closing, the Acquiring Participants and the Exiting Participants will work together to provide timely notification to taxing authorities of the Closing and will use commercially reasonable efforts to have any taxing authority imposing any taxes or assessments on or with respect to the Project assess and levy such taxes or assessments directly against each Party in accordance with its respective Ownership Interest in the property taxed. The manner of making such notifications will be addressed in the Closing Statement.

16.3 IRS Exclusion . The Parties hereby elect to be excluded from the application of Subchapter “K” of Chapter 1 of Subtitle “A” of the Internal Revenue Code of 1986, or such portion or portions thereof as may be permitted or authorized by the Secretary of the Treasury or

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its delegate insofar as such subchapter, or any portion or portions thereof, may be applicable to the Parties hereunder.

17. Representations and Warranties; Opinions of Counsel

17.1 Requisite Power and Authority . Each Party represents and warrants to the other Parties that it has the requisite power and authority to execute this Restructuring Agreement and that the person executing this Restructuring Agreement on its behalf has the requisite authority to do so and, subject to the receipt of requisite Regulatory Approvals, to perform its obligations set out in this Restructuring Agreement; the execution and delivery of this Restructuring Agreement and the performance of the obligations set out herein have been duly authorized by all necessary action on the part of each Party; and the obligations set out herein are valid and binding obligations of such Party, enforceable against such Party in accordance with the terms and conditions hereof, except to the extent that enforceability hereof or thereof may be limited by applicable bankruptcy, insolvency, reorganization, moratorium or other similar laws generally affecting creditors’ rights and by equitable principles, regardless of whether enforcement is sought in equity or at law.

17.2 No Violation . Each Party, to the best of its knowledge and upon reasonable inquiry, represents and warrants to the other Parties that the execution and delivery of this Restructuring Agreement by such Party, and the performance by such Party of all of its obligations hereunder, will not violate any term, condition or provision of its Charter Documents; any applicable Law by which the Party is bound; any applicable court or administrative order or decree; or any agreement or contract to which it is a party. Further, each Party represents and warrants to the other Parties that, to the best of its knowledge and upon reasonable inquiry, there is no claim pending or threatened against it which seeks a writ, judgment, order or decree restraining, enjoining or otherwise prohibiting or making illegal any of the transactions contemplated by this Restructuring Agreement or which could result in the filing of any mechanic’s or materialman’s lien against the SJGS Plant Site, other than a disclosed appeal of a Regulatory Approval.

17.3 Opinions of Counsel . On or before the Execution Date, counsel for each Party will provide its opinion to each of the other Parties, in form and substance reasonably acceptable to the Party to which such opinion is delivered, that the Party is in compliance with the representations and warranties given in this Section 17. The form of such opinion of counsel is provided in Exhibit D .

18. Relationship of Parties

18.1 Several Obligations . The covenants, obligations and liabilities of the Parties are, except as otherwise specifically provided herein, intended to be several and not joint or collective. At no time will a non-defaulting Party be responsible for making payments required under this Restructuring Agreement on behalf of any other Party. Each Party will be individually responsible for its own covenants, obligations and liabilities as provided for herein.

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18.2 No Joint Venture or Partnership . Nothing in this Restructuring Agreement will be construed to create an association, joint venture, trust or partnership, or to impose a trust or partnership covenant, obligation or liability on or with regard to any one or more of the Parties. No Party or group of Parties will be under the control of or will be deemed to control any other Party or the Parties as a group. Except as expressly provided in this Restructuring Agreement, the Mine Reclamation Agreement, the Decommissioning Agreement and the SJPPA, no Party will be the agent of or have a right or power to bind any other Party without its express written consent.

19. Establishment of Environmental Baseline

19.1 Baseline Environmental Study . In furtherance of their common interest with respect to the identification of potential environmental Liabilities, the Participants have engaged an independent, third-party environmental consultant (“Consultant”) to complete a confidential baseline environmental self-evaluation (“Baseline Environmental Study” or “BES”) of SJGS and its operations. Associated with the BES will be a multi-media compliance audit (“Environmental Audit”) to determine compliance with applicable environmental requirements from the previous SJGS audit to the present. The BES and the Environmental Audit will be funded as Operating Work under the SJPPA. The purpose of the BES and the Environmental Audit is to establish a baseline of environmental conditions in anticipation of the Exiting Participants’ exit from active involvement in the operation of SJGS on the Exit Date. It is the intent of the Participants that the Consultant’s work and communications be protected to the fullest legal extent possible under Law, including under any attorney-client privilege, environmental audit privilege, self-critical analysis privilege and the attorney work product doctrine. The Consultant has been engaged and is being directed by counsel jointly representing the Participants. The Consultant’s work and communications, including the Draft Report, Final Report and Further Audit addressed below, have been and will continue to be treated as privileged and confidential pursuant to the retention agreement between the Consultant and the counsel retained by the Participants pursuant to this Section 19.1, and will be included as Defense Materials pursuant to the Joint Defense and Confidentiality Agreement effective December 9, 2009 and the Addendum to Joint Defense and Confidentiality Agreement effective January 31, 2010.

19.2 Scope of BES and Environmental Audit . The scope of work for the BES and Environmental Audit has been developed by agreement of all Participants and will include: (i) review and analysis of data, documents and information, such as monitoring data for air emissions, surface and groundwater discharges, to identify potential or actual emissions, spills or leaks related to SJGS; and (ii) interviews of key past or present Operating Agent personnel (as identified and agreed upon by all Participants) with knowledge of past and present SJGS operations. The BES and Environmental Audit may identify environmental issues that require further assessment or investigation. To the extent possible (based upon regulatory requirements) and by agreement of all the Participants, additional environmental assessments such as document review, studies, data collection, sampling, analysis of soil, surface water, and groundwater sampling and similar activities may be conducted with a desired completion date of June 30, 2015, or as otherwise agreed by the Participants. Issues of concern that are already identified and that are the current subject of monitoring, investigative and remediation activities in accordance with regulatory, permitting or other legal requirements will be excluded from further

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assessment in the BES; provided, however, that such issues and remediation activities will be identified and listed in the Final Report.

19.3 Draft Report . The Consultant will prepare and provide a draft confidential baseline environmental report (“Draft Report”) setting forth the Consultant’s findings and recommendations, which Draft Report will be distributed to all the Participants for review and comment.

19.4 Final Report . After receiving and considering the Participants’ comments, the Consultant will prepare a confidential final BES report for SJGS and its operations (“Final Report”) setting forth the Consultant’s findings and recommendations, if any, to address any environmental issues in accordance with any applicable environmental Laws. The Final Report will be directed to all the Participants and each and all of the Participants may rely on the Final Report. The Draft Report, Final Report and Further Audit are privileged and confidential pursuant to this Section 19. If the Operating Agent or a Participant is requested by an insurance carrier or broker, in connection with an application for coverage, or renewal of coverage, or in connection with a claim filed by the Operating Agent or a Participant, to provide information in regard to the operation or environmental compliance of SJGS, the Operating Agent or the Participant may provide factual information to the insurance carrier or broker pertinent to the application for coverage, or renewal of coverage, or the filed claim, including based upon findings contained in the Draft Report, the Final Report or the Further Audit but may not provide a copy of the Draft Report, Final Report or the Further Audit. Any Participant providing such factual information to an insurance carrier or broker will seek an agreement from the insurance carrier or broker to maintain the confidentiality of such information.

19.5 Remediation or Corrective Action . If the Final Report identifies any environmental issues at SJGS that require remediation or corrective action or similar activities that are not being currently addressed, then, as part of Operating Work and funded as such, the Operating Agent will to the extent possible (given any constraints and/or schedule that may be imposed by the regulatory agency overseeing the remediation) on or before thirty (30) days prior to the Exit Date remediate, or commence the remediation of, any and all environmental issues identified in the Final Report, with responsibility for the cost of such remediation, corrective action, or similar activities to be borne by Parties or, if applicable, their respective insurance carriers, based on the Parties’ respective pre-Exit Date Ownership Interests in the facilities giving rise to the Liability.

19.6 Further Audit . After the Final Report, but prior to the Exit Date, the Operating Agent will complete an additional environmental audit of SJGS (the “Further Audit”) to identify environmental issues, if any, that may have arisen subsequent to the completion of the Final Report. The scope of work for the Further Audit will be developed by agreement of all the Participants. The Further Audit will be treated as confidential, as set forth in Section 19.1, and will be directed to all the Participants (all of whom may rely on the Further Audit). The Further Audit and any remediation undertaken pursuant to the Further Audit will be funded as Operating Work, the cost responsibilities for which will be borne by Parties based on the Parties’ respective pre-Exit Date Ownership Interests in the facilities giving rise to the Liability. The Final Report may be supplemented to the extent updates are required by the Further Audit.

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19.7 Subsequently Discovered Environmental Issues . The Parties acknowledge that: (i) the BES, the Final Report and the Further Audit may not discover or report all environmental issues that existed prior to the date thereof; and (ii) there may be exposure to claims for environmental Liabilities for changes in applicable Law after the Exit Date. Liabilities for environmental issues identified after the Exit Date will be resolved pursuant to Section 20.

19.8 Claims against Predecessors . Nothing in this Section 19 affects the right of a Party to seek contribution from or otherwise make claims against any Predecessor with respect to environmental Liabilities arising from an event prior to such Party’s acquisition of its Ownership Interest, provided that any Party seeking such contribution is not relieved of its obligation to pay any amounts it owes under this Section 19.

20. Liability and Indemnification

20.1 Liabilities Defined . Except as expressly limited, the term “Liabilities” as used in this Restructuring Agreement means all liabilities, claims, demands, actions, damages, fines, penalties, remedial or corrective action costs, and causes of action whatsoever, including without limitation the reasonable fees and disbursements of the applicable Party’s external attorneys and their staff, and costs and expenses, including but not limited to costs of consultants and experts and other litigation costs reasonably incurred in investigating, preparing, prosecuting or defending against any litigation or claim, action, suit, proceeding or demand of any kind or character for which indemnification is provided hereunder. The term “Liabilities” specifically and expressly includes: (i) all liabilities of any kind or character arising out of or related to the contamination of the SJGS Plant Site by any hazardous substance, hazardous waste or any environmental pollutant or contaminant; or (ii) the violation of any permit applicable to SJGS; or (iii) the violation of any environmental Law, including violations of the Comprehensive Environmental Response Compensation and Liability Act, the Federal Clean Air Act, the Federal Clean Water Act and the Federal Resource Conservation and Recovery Act; provided, however, that “Liabilities” under this Restructuring Agreement do not include costs for planning or implementing decommissioning of the San Juan Project, which are addressed in the Decommissioning Agreement, or the costs of mine reclamation, which are addressed in the Mine Reclamation Agreement.

20.2 Liabilities Arising Prior to Exit Date . Except in situations when the event giving rise to the Liability is the result of Willful Action of the Operating Agent or a Party, all Parties will be responsible for Liabilities arising from SJGS plant operations and ownership prior to the Exit Date, based on the Parties’ respective pre-Exit Date Ownership Interests in the facilities giving rise to the liability. If the Liability is the result of Willful Action of the Operating Agent or a Party, the Operating Agent or the Party will be responsible for such Liabilities within the limitations of the SJPPA.

20.3 Liabilities Arising After Exit Date . Only the Remaining Participants will be responsible for Liabilities arising from SJGS plant operations or ownership after the Exit Date based on the Remaining Participants’ respective post-Exit Date plant ownership interests in the facilities giving rise to the Liability.

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20.4 Apportionment of Liabilities . It is recognized that some events giving rise to Liabilities may potentially begin prior to the Exit Date and continue after the Exit Date; in such event, responsibility will be apportioned based on the relative time periods before and after the Exit Date and pursuant to the provisions of Sections 20.2 and 20.3.

20.5 Limitation of Liability for Willful Action . For claims made prior to the Exit Date, the ten million dollar ($10,000,000) limitation of liability in Sections 36.6 and 36.9 of the SJPPA will apply. For claims made on or after the Exit Date, the limitation of liability for each occurrence of Willful Action will be fourteen million dollars ($14,000,000). As of the Exit Date, all references in Sections 36.6 and 36.9 of the SJPPA to a limitation of liability of ten million dollars ($10,000,000) for each occurrence of Willful Action will be amended to increase that amount to a limitation of liability of fourteen million dollars ($14,000,000) for each occurrence of Willful Action.

20.6 Several Liability . All Parties’ obligations for Liability and indemnity hereunder will be several and not joint or collective. Each Party will be individually responsible for its own covenants, obligations and Liabilities as provided for herein.

20.7 Claims Arising After Exit Date . If on or after the Exit Date a claim for Liability arising from SJGS operations or ownership is made against one or more of the Parties, or by any Party against another Party (in each case, including the Operating Agent), then the following will occur:

20.7.1 In the event a claim for Liability is brought against any Party asserting claims for Liability arising from ownership or operation of SJGS, said Party will notify the other Parties in writing within ten (10) Business Days after the Party learns of the claim for Liability.

20.7.2 The Exiting Participants and the Remaining Participants will confer promptly to determine if the event giving rise to the Liability occurred prior to or on or after the Exit Date.

20.7.3 If all the Exiting Participants and the Remaining Participants agree that the event giving rise to the Liability occurred prior to the Exit Date, all Parties will bear their respective proportionate shares of any resulting Liability, based on the Parties’ respective pre-Exit Date Ownership Interests in the facilities giving rise to the Liability. The Parties’ pre-Exit Date Ownership Interests in the Project facilities are shown in Exhibit E .

20.7.4 If all the Exiting Participants and the Remaining Participants agree that the event giving rise to the Liability occurred on or after the Exit Date, the Remaining Participants, based on their respective post-Exit Date Ownership Interests in the facilities giving rise to the Liability, will indemnify, defend and hold harmless the Exiting Participants and their agents, affiliates, members, officers, directors, commissioners, Boards, employees, successors and assigns from and against any and all Liabilities of any kind or character resulting from such claim for Liability arising out of or related to SJGS operations and ownership on or after the Exit Date.

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20.7.5 If all the Exiting Participants and the Remaining Participants cannot agree whether the event giving rise to the Liability occurred prior to, on or after the Exit Date, then the Parties will unanimously agree upon the retention of an independent third-party consultant (with expertise in the subject matter giving rise to the liability) who will be tasked with determining whether the event giving rise to the Liability occurred before or on or after the Exit Date (or the extent to which the event giving rise to the liability occurred before or on or after the Exit Date). To the extent permitted by law, the Parties will provide for the confidentiality of the independent third-party consultant’s determination and will share equitably in the consultant’s fees and costs. The determination of the independent third-party consultant will be final and binding on the Parties except as provided in Sections 20.7.8 and 20.7.9 and is not arbitrable under Section 23.

20.7.6 To the extent the independent third-party consultant determines that the event giving rise to the Liability occurred prior to the Exit Date, the provisions of Section 20.7.3 will apply.

20.7.7 To the extent the independent third-party consultant determines that the event giving rise to the Liability occurred on or after the Exit Date, the provisions of Section 20.7.4 will apply.

20.7.8 If all the Parties have agreed, or the independent third-party consultant has determined, that the event giving rise to the Liability occurred prior to the Exit Date, but there is a final judicial determination that the event giving rise to the Liability occurred (fully or partially) on or after the Exit Date, the Remaining Participants, based on their respective post-Exit Date plant ownership interests in the facilities giving rise to the Liability, will indemnify, defend and hold harmless the Exiting Participants and their agents, affiliates, members, officers, directors, commissioners, Boards, employees, successors and assigns from and against any and all Liabilities of any kind or character resulting from such claim for Liability arising out of or related to SJGS plant operations and ownership on or after the Exit Date (to the extent the event is judicially determined to have occurred after the Exit Date), including a refund to the Exiting Participants of sums paid by the Exiting Participants for any Liability; provided, that no Party will: (a) commence a lawsuit seeking a judicial determination to reverse the agreement of the Parties or the determination of the independent third-party consultant as to when the events giving rise to the Liability occurred; or (b) assert or support a position in a lawsuit commenced by a third party that would have the effect of reversing the agreement of the Parties or the determination of the independent third-party consultant as to when the events giving rise to the Liability occurred. As used in Sections 20.7.8 and 20.7.9, “final judicial determination” refers to: (x) the decision of a trial court that has become final by virtue of the appeal period having expired without an appeal having been taken; or (y) the final decision of an appellate court from which no rehearing or further appeal may be taken.

20.7.9 If all the Parties have agreed, or the independent third-party consultant has determined, that the event giving rise to the Liability occurred on or after the Exit Date,

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but there is a final judicial determination that the event giving rise to the Liability occurred (fully or partially) before the Exit Date, the Exiting Participants, based on their pre-Exit Date plant ownership interests in the facilities giving rise to the Liability, will indemnify, defend and hold harmless the Remaining Participants and their agents, affiliates, members, officers, directors, commissioners, Boards, employees, successors and assigns from and against the Exiting Participants’ individual proportionate shares of said Liability arising out of or related to SJGS plant operations and ownership prior to the Exit Date (to the extent the event is judicially determined to have occurred before the Exit Date), including a refund to the Remaining Participants of a proportionate share of sums paid by the Remaining Participants for any Liability; provided, however, that no Party will: (a) commence a lawsuit seeking a judicial determination to reverse the agreement of the Parties or the determination of the independent third-party consultant as to when the events giving rise to the Liability occurred; or (b) assert or support a position in a lawsuit commenced by a third party that would have the effect of reversing the agreement of the Parties or the determination of the independent third-party consultant as to when the events giving rise to the Liability occurred.

20.8 Claims against Predecessors . Nothing in this Section 20 affects the right of a Party to seek contribution from or otherwise make claims against any Predecessor with respect to environmental Liabilities arising from an event prior to such Party’s acquisition of its Ownership Interest, provided that any Party seeking such contribution is not relieved of its obligation to pay any amounts it owes under this Section 20.

20.9 PNM Responsibility . PNM will defend, indemnify and hold harmless the other Parties and their agents, affiliates, members, officers, directors, commissioners, Boards, employees, successors and assigns from and against Liabilities to the extent arising from the development, operation and/or ownership by PNM (or PNM’s affiliate, assignee, successor, licensee or lessee) of any new future use of property at or adjacent to the SJGS Plant Site, including the development, operation or ownership of any future gas-fueled electric generating plant to be developed by PNM (or PNM’s affiliate, assignee, successor, licensee or lessee) at or adjacent to the SJGS Plant Site.

20.10 Indemnification Procedures .

20.10.1 A Party seeking indemnification hereunder (the “Indemnified Party”) will give prompt written notice to the Party from whom indemnification is sought (the “Indemnifying Party”) of the assertion of any Liability for which indemnification is sought. The notice will set forth in reasonable detail the factual basis asserted for the Liability and the claimed or estimated amount of the Liability. Notwithstanding the foregoing, the failure or delay of the Indemnified Party to so notify the Indemnifying Party will not relieve the Indemnifying Party of its indemnification obligations under this Restructuring Agreement unless, and only to the extent that, such failure or delay materially and adversely prejudiced the Indemnifying Party. Nothing in this Section 20.10.1 is intended nor will be construed to toll or otherwise affect the operation of any applicable statute of limitations.

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20.10.2 With respect to any Liability as to which indemnification is sought, if the Indemnifying Party has acknowledged in writing its indemnification obligations under this Restructuring Agreement without qualification or reservation of rights, the Indemnifying Party has the right at its own expense to conduct and control the defense, compromise or settlement of such Liability, utilizing counsel of its choice, subject to the limitations set forth in this Section 20.10. Such counsel must be reasonably acceptable to the Indemnified Party. The Indemnified Party may participate at its own expense in such defense, compromise or settlement utilizing its own counsel. Notwithstanding the foregoing, the Indemnified Party has the right to conduct and control the defense, compromise or settlement of any Liability with counsel of its choice and at the Indemnifying Party’s expense if: (i) the Indemnifying Party has not delivered the written acknowledgement of indemnification obligations and given notice of its decision to conduct and control the defense of such Liability within thirty (30) days after notice of such Liability is served; (ii) the Indemnifying Party fails to conduct such defense diligently and in good faith; (iii) the Indemnified Party reasonably determines, based upon the advice of counsel (including in-house counsel), that the use of counsel selected by the Indemnifying Party to represent the Indemnified Party would present such counsel with an actual or potential conflict of interest to which the Indemnified Party and, if necessary, the Indemnifying Party has not consented in writing; (iv) the claim for Liability seeks injunctive or other non-monetary relief against the Indemnified Party; or (v) the Liability relates to or otherwise arises in connection with any criminal or regulatory proceeding.

20.10.3 The Indemnifying Party and the Indemnified Party will, and will cause their respective Affiliates and representatives to, cooperate with the defense or prosecution of any claim. Such cooperation includes furnishing such records, information and witnesses and attending such conferences, discovery proceedings, hearings, trials and appeals as may be reasonably requested by the Indemnifying Party of the Indemnified Party or the Indemnified Party of the Indemnifying Party in connection with the defense or prosecution of any claim.

20.10.4 Except as set forth below, no claim may be settled or compromised by the Indemnified Party without the prior written consent of the Indemnifying Party or by the Indemnifying Party without the prior written consent of the Indemnified Party, in each case which consent will not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing, the Indemnified Party has the right to pay, settle or compromise any Liability, provided that the Indemnified Party waives all rights against the Indemnifying Party to indemnification under this Section 20 with respect to such Liability unless the Indemnified Party sought the consent of the Indemnifying Party to such payment, settlement or compromise but the Indemnifying Party unreasonably withheld, conditioned or delayed such consent. The Indemnifying Party has the right to consent to the entry of a judgment or enter into a settlement with respect to any Liability without the prior written consent of the Indemnified Party, if the judgment or settlement (i) involves only the payment of money damages to be paid in full by the Indemnifying Party concurrently with the effectiveness of such judgment of settlement; (ii) does not contain any restriction or condition that would reasonably be expected to have a future adverse effect on the Indemnified Party or the conduct of its business; (iii) does not

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include any admission of wrongdoing; (iv) includes in any settlement documents and/or release a statement that the matter is being settled without agreement of the Indemnified Party as allowed by this Section 20.10.4; and (v) includes, as a condition to any settlement or other resolution, a complete and irrevocable release of the Indemnified Party from all liability for the claim on which the judgment or settlement is based.

20.11 Anti-Indemnity Provisions . The Parties acknowledge the potential applicability of NMSA 1978, §§ 56-7-1 and 56-7-2. Any agreement to indemnify contained herein will be enforced only to the extent it requires the Indemnifying Party to indemnify and hold harmless the Indemnified Party, including its agents, affiliates, members, officers, directors, commissioners, Boards, employees, successors and assigns, against liabilities: (i) only to the extent that the liabilities are caused by, or arise out of, the acts or omissions or negligence of the Indemnifying Party or its agents, affiliates, members, officers, directors, commissioners, Boards, employees, successors and assigns; and (ii) except to the extent such liabilities arise out of the negligence, actions or omissions of an Indemnified Party or such Indemnified Party’s agents or employees or independent contractors.

20.12 Internal Counsel . There will be no indemnification with respect to fees or expenses of internal counsel of a Party.

20.13 Willful Action . No Party (including the Operating Agent) committing Willful Action will be indemnified or held harmless by the other Parties for the consequences of the Party’s Willful Action.

20.14 Damages . Notwithstanding Section 20.1, in no event will any Party be liable under any provision of this Restructuring Agreement for any indirect, punitive or incidental damages or costs of any other Party (including loss of revenue, cost of capital and loss of business reputation or opportunity), whether based in contract, tort (including, without limitation, negligence or strict liability), or otherwise, and the Parties hereby waive, release and discharge one another from all such indirect, punitive and incidental damages and costs; provided, that this Section 20.14 does not affect or negate the provisions of Section 23.8 regarding Penalty Interest or the provisions of Section 20 regarding obligations to indemnify.

20.15 Mitigation of Damages . Each Party will take appropriate and prudent actions reasonably to mitigate any damages such Party may suffer as a result of the conduct or Default of another Party.

20.16 Anaheim and M-S-R . Anaheim (which includes its Public Utilities Department) and M-S-R are governmental entities whose liability is limited by the California Government Claims Act (Government Code §§ 810 – 998.3) and any Liability or indemnity assumed by Anaheim or M-S-R in this Restructuring Agreement will be limited by the provisions of the California Government Claims Act. Nothing in this Restructuring Agreement is intended to create or will be construed or applied to create any obligation, agreement, covenant or promise to indemnify, hold harmless or defend which is against public policy, void and unenforceable. Notwithstanding any other provision of this Restructuring Agreement, the payment for all purchases, fees or charges made by Anaheim or M-S-R under this Restructuring Agreement will

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be made from the legally available revenues of M-S-R or the legally available revenues of the Anaheim Electric System. In no event will the obligation to pay under this Restructuring Agreement be considered an obligation against the general faith and credit or general taxing power of Anaheim or of M-S-R or any of the members of M-S-R.

20.17 Southern California Public Power Authority . SCPPA is a joint exercise of powers agency organized under the laws of the State of California, created to acquire, construct, finance, operate and maintain generation and transmission projects on behalf of its members. In no event will the obligation to pay under this Restructuring Agreement be considered an obligation against the general faith and credit or taxing power of any member of SCPPA.

20.18 Farmington and Los Alamos . Farmington (and the Farmington Electric Utility System) and Los Alamos are governmental entities whose liability is limited by the New Mexico Tort Claims Act, NMSA 1978, §§ 41-4-1 through 41-4-27, and any liability or indemnity assumed by Farmington and the Farmington Electric Utility System or Los Alamos in this Restructuring Agreement will be limited by the provisions of the New Mexico Tort Claims Act. Notwithstanding any other provisions of this Restructuring Agreement, the payment for all purchases, fees or charges made by Farmington and Los Alamos under this Restructuring Agreement will be made from the legally available revenues of Farmington’s and/or Los Alamos’s Electric Utility System. In no event will the obligation to pay under this Restructuring Agreement be considered an obligation against the general faith and credit or general taxing power of Farmington or Los Alamos.

20.19 Utah Associated Municipal Power Systems . UAMPS is a joint action agency organized under the laws of the State of Utah, created to acquire, construct, finance, operate and maintain generation and transmission projects on behalf of its members. In no event will the obligation to pay under this Restructuring Agreement be considered an obligation against the general faith and credit or taxing power of any member of UAMPS.

21. Insurance Coverage for Continuing Obligations

21.1 Occurrence-based Policies . All occurrence-based policies of Operating Insurance required by the SJPPA will be in effect on the Exit Date (auto liability, workers’ compensation, general liability, crime and property). The Exiting Participants will not be eligible for inclusion in occurrence-based Operating Insurance renewed after the Exit Date.

21.2 Claims-Made Policies .

21.2.1 Except as provided in Section 21.2.2, after the Exit Date the Exiting Participants will not be eligible for inclusion in the Operating Insurance policies that are claims-made policies (environmental liability, excess liability, fiduciary liability and employment practices liability) (each a “Claims-Made Policy”) and, as of the Exit Date, all obligations of the Operating Agent to procure Claims-Made Policies for the benefit or protection of the Exiting Participants will cease.

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21.2.2 If an Exiting Participant desires to purchase continuing or stand-alone “tail” coverage (collectively, “Continuing Coverage”) under a Claims-Made Policy that would or may provide coverage for risks insurable under the insurance coverage form in effect at the time of a covered loss, for which the Exiting Participant has potential responsibility, the Operating Agent will, upon timely written notice from the Exiting Participant, work with the Exiting Participant to provide the Exiting Participant the opportunity to obtain such Continuing Coverage. Continuing Coverage may be procured through the purchase of a stand-alone Claims-Made Policy issued to the Exiting Participant or by one or more endorsements on Claims-Made Policies purchased by the Operating Agent. If requested in writing by an Exiting Participant, the Operating Agent will provide an analysis to the Exiting Participant as to coverage options. The availability, if any, of Continuing Coverage is dependent on market conditions. Upon the renewal of a Claims-Made Policy under which an Exiting Participant has Continuing Coverage, the Operating Agent, upon written request, will provide the Exiting Participant a copy of the policy with all endorsements demonstrating compliance with this Section 21.2.2; provided, however, that if in the judgment of the Operating Agent portions of a policy are proprietary, confidential or otherwise not disclosable, and these portions of the policy do not impact the premium allocated or relate specifically to the SJGS Plant Site, including exposures, loss experience, severity and frequency of loss, then the Operating Agent may redact such portions with a full explanation to the Exiting Participant of the reason for the redaction.

21.2.3 Each Exiting Participant electing Continuing Coverage under a Claims-Made Policy procured by the Operating Agent for or on behalf of the Exiting Participant will pay for the Continuing Coverage during the period in which the Continuing Coverage is or will be in effect as set forth below.

21.2.3.1 If Continuing Coverage is procured by the purchase of a stand-alone Claims-Made Policy issued to the Exiting Participant, the Exiting Participant will pay the associated premium to the Operating Agent.

21.2.3.2 If Continuing Coverage is procured by one or more endorsements on Claims-Made Policies purchased by the Operating Agent, the Exiting Participant will pay its allocated share of the premium associated with the Continuing Coverage. The determination of the allocated share will be based on factors customarily employed, including the property affected, exposures, loss experience and severity and frequency of loss.

21.2.3.3 With respect to Continuing Coverage procured as provided in Section 21.2.3.2, the Operating Agent will invoice the allocated share of the premium to the Exiting Participant, with necessary and sufficient supporting information, and will timely provide all additional supporting information as the Exiting Participant may reasonably request. If there is a dispute between the Operating Agent and the Exiting Participant as to the Exiting Participant’s allocable share of the premium, the Exiting Participant will pay the invoice and the disputing Parties will retain the services of a mutually agreed independent

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third party (broker or other consultant) with expertise in insurance matters to resolve the dispute. The fees and expenses of the independent third party will be shared equally among the disputing Parties. Upon the resolution of the dispute, an appropriate adjustment will be made to the invoice, if required. Any disputes under this Section 21.2.3 are not arbitrable under Section 23.

21.2.4 Nothing in this Section 21.2 prevents an Exiting Participant that may wish to purchase Continuing Coverage from doing so on its own, and at its own expense, without involvement of the Operating Agent. The Operating Agent will reasonably cooperate with the Exiting Participant in its efforts to obtain Continuing Coverage.

21.2.5 In the event an Exiting Participant that has obtained Continuing Coverage no longer desires to have Continuing Coverage under any Claims-Made Policy procured by the Operating Agent, the Exiting Participant must give the Operating Agent at least one hundred and fifty (150) days written notice prior to the next incepting coverage term of the Claims-Made Policy.

21.3 Other Insurance Coverage Matters. Prior to the Exit Date, if requested by an Exiting Participant, the Operating Agent will consult with the Exiting Participant in reference to insurance issues related to the departure of the Exiting Participants, including insuring physical property on a cash value basis.

21.4 Obligation to Maintain Policies . The Operating Agent and the Remaining Participants will continue to obtain and maintain Operating Insurance as provided for in the SJPPA, and the Operating Agent will, upon written request, including email, provide within five (5) Business Days an Exiting Participant a certificate of insurance as proof of continued coverage. For insurance policies required to be provided by vendors or service providers whose services, in the reasonable opinion of the Operating Agent, could expose a Party to Liability, then, where permitted by such policies, such Party will be included as an additional insured on such policies, including all applicable endorsements.

22. Assignments

22.1 Assignment . This Restructuring Agreement and the rights, duties and obligations hereunder may not be assigned or delegated by any Party without the prior written consent of the other Parties (such consent not to be unreasonably withheld, conditioned or delayed); provided, however, any Party may without the consent of any other Party (and without relieving itself from liability hereunder) but with prior notice to the other Parties:

22.1.1 transfer, sell, pledge, encumber or assign this Restructuring Agreement as collateral in connection with any financing arrangements;

22.1.2 transfer or assign this Restructuring Agreement to an Affiliate of such Party so long as (i) such Affiliate’s creditworthiness is equal to or higher than that of the assigning Party; and (ii) such assignee has agreed in writing to unconditionally assume

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and be bound by the terms and conditions hereof and all of the transferring Party’s obligations hereunder; or

22.1.3 transfer or assign this Restructuring Agreement to any entity succeeding to all or substantially all of the assets of the transferring Party so long as the assignee’s creditworthiness is equal to or higher than that of the assigning Party and such assignee has agreed in writing to unconditionally assume and be bound by the terms and conditions hereof and all of the transferring Party’s obligations hereunder.

Any (i) mortgagee, trustee or secured party under present or future deeds of trust, mortgages, indentures or security agreements of any of the Parties and any successor or assign thereof; (ii) receiver, referee, or trustee in bankruptcy or reorganization of any of the Parties, and any successor by action of law or otherwise; and (iii) purchaser, transferee or assignee or any thereof may, without need for the prior consent of the other Parties and subject to the provisions of Section 22.2, succeed to and acquire all the rights, titles and interests of such Party in this Restructuring Agreement, and upon such succession or acquisition, will assume all of the obligations of such Party in this Restructuring Agreement arising from and after the date of the succession and may take over possession of or foreclose upon said property, rights, titles and interests of such Party.

22.2 Assignee Responsibility . Any (i) mortgagee, trustee or secured party; (ii) receiver, referee or trustee appointed pursuant to the provisions of any present or future mortgage, deed of trust, indenture or security agreement creating a lien upon or encumbering the rights, titles or interests of any Party in, to and under this Restructuring Agreement and any successor thereof by action of law or otherwise; and (iii) purchaser, transferee or assignee of any thereof, will not be obligated to pay any monies accruing on account of any of the obligations or duties of such Party under this Restructuring Agreement incurred prior to the taking of possession, the effectiveness of transfer, or the initiation of foreclosure or other remedial proceedings by such mortgagee, trustee or secured party.

22.3 Parties not Relieved of Obligations . No Party will be relieved of any of its obligations and duties to the other Parties by a transfer or assignment under this Section 22 without the express prior written consent of the remaining Parties, which consent will not be unreasonably withheld, conditioned or delayed.

23. Dispute Resolution and Default

23.1 Amicable Resolution . If a dispute between or among any of the Parties should arise under this Restructuring Agreement, or in relation to the rights or obligations of the Parties under this Restructuring Agreement, the Parties will first seek to resolve the dispute as set forth in this Section 23.1.

23.1.1 The dispute resolution process will be initiated by the delivery of a written notice by a Party (“Noticing Party”) of the dispute (“Notice of Dispute”) to the Party with which a dispute is claimed. The Notice of Dispute will specify the existence, nature and extent of the dispute. Copies of the Notice of Dispute will also be served on all other

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Parties. The Notice of Dispute will specifically state the sums allegedly due, any non-monetary obligation allegedly not performed, or both if applicable.

23.1.2 Within fifteen (15) Business Days of receipt of the Notice of Dispute, the Party alleged not to be performing will (i) pay any undisputed amount to the Party entitled to such payment, and deposit any disputed amount into escrow in accordance with an escrow agreement consistent with this Section 23; and (ii) commence performance of any disputed non-monetary obligation, but in either case may do so under protest (the “Protest”).

23.1.2.1 The Protest will be in writing, will accompany the disputed payment into escrow or precede the commencement of performance of the disputed non-monetary obligation, and will specify the basis of the Protest. Copies of the Protest will be served by the protesting Party (“Protesting Party”) on all other Parties.

23.1.2.2 The escrow agreement will (i) provide that amounts deposited into escrow will be held in escrow until the Noticing Party and the Protesting Party mutually direct otherwise or until an award of arbitrators directs otherwise; (ii) direct the escrow agent to deposit the escrowed amounts into an interest-bearing account with appropriate liquidity considering the nature and likely duration of the dispute; and (iii) provide that fees for establishing the escrow be paid by the Protesting Party and that fees for other services of the escrow agent may be deducted periodically from the funds held in escrow or as otherwise agreed by the Noticing Party, Protesting Party and escrow agent. The escrow agreement may contain other appropriate terms customarily required in such agreements by escrow agents.

23.1.3 Within fifteen (15) Business Days of the giving of a Notice of Dispute under Section 23.1.1, or within ten (10) Business Days after the service of a Protest under Section 23.1.2, executive representatives of the Parties involved in the dispute with authority to resolve the dispute will meet at a mutually acceptable time and place to attempt to negotiate a timely and amicable resolution of the dispute. If an executive of a Party involved in the dispute intends to be accompanied by counsel, the other Party or Parties involved in the dispute must be given at least five (5) Business Days’ written notice of such intent and such other Parties may also be accompanied by counsel. All negotiations will be confidential and will be treated as compromise and settlement negotiations under New Mexico law. If the executive representatives of the Parties are unable to resolve the dispute within sixty (60) days of the Notice of Dispute (or such other period as they may agree to), any Party involved in the dispute may call for submission of the dispute to arbitration, which call will be binding upon all other affected Parties.

23.2 Call for Arbitration . The Party calling for arbitration must give written notice to all other Parties (“Arbitration Notice”), setting forth in the Arbitration Notice in adequate detail the entity against whom relief is sought, the nature of the dispute, the amount, if any, involved in

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such dispute, and the remedy sought by such arbitration proceedings, which may include monetary, equitable and declaratory relief. Within twenty (20) Business Days after receipt of the Arbitration Notice, any other Party may submit its own statement of the matter at issue and set forth in adequate detail additional related matters or issues to be arbitrated, with copies of such notice provided to all other Parties. Thereafter, the Party calling for arbitration will have ten (10) Business Days in which to submit a written rebuttal statement, copies of which must be provided to all other Parties.

23.3 Selection of Arbitrators .

23.3.1 The Parties involved in the arbitration will seek to agree upon a panel of three (3) neutral arbitrators as follows. Within ten (10) days after service of the written rebuttal statement, the Parties representing each side of the dispute will provide to the Parties representing the other side of the dispute a list of up to five (5) suggested arbitrators having the qualifications required by Section 23.3.2 and a summary of each such suggested arbitrator’s experience and qualifications. Within five (5) Business Days thereafter, the Parties involved in the arbitration will meet and confer by telephone or in person to seek to agree upon a panel of three (3) neutral arbitrators from the lists that have been exchanged. If such agreement is not reached as the result of such meeting, the Parties representing each side of the dispute will provide a second list of suggested arbitrators to one another, and the Parties will meet and confer again within five (5) Business Days thereafter to attempt to reach agreement upon a panel of three (3) neutral arbitrators. If such agreement on arbitrators is reached, the Parties will proceed to arbitration as further set forth in this Section 23.

23.3.2 If the Parties involved in the arbitration are not able to agree upon a complete panel of three (3) neutral arbitrators, such Parties will select the arbitrators upon which agreement has not been reached as follows. The Parties will request from the American Arbitration Association (“AAA”) (or similar organization as the arbitrating Parties agree upon) (“Arbitration Organization”) a list of seven (7) arbitrators with names and biographical sketches and specific qualifications relating to the case to be heard. The proposed arbitrators must be retired judges or other attorneys with experience in complex business disputes. The Parties involved in the arbitration will each advise the Arbitration Organization of its order of preference of such arbitrators by numbering from one (1) to seven (7) each name on the list (with one (1) being the most preferred arbitrator) and submitting the numbered lists in writing to the Arbitration Organization. Depending upon the number of arbitrators to be selected, the name or names with the lowest combined numbers will be appointed as the remaining neutral arbitrator(s). In the event more than one name on the list has the same lowest combined score, the tie will be broken by lot. Should the Parties agree that one list of seven (7) is insufficient to obtain a total of three (3) neutral arbitrators with the required qualifications, an additional list of arbitrators may be requested from the Arbitration Organization.

23.3.3 No person will be eligible for appointment as an arbitrator who is an officer or employee of any of the Parties to the dispute or is otherwise interested in the matter to be arbitrated.

23.4 Arbitration Procedures . Except as otherwise provided in this Section 23 or otherwise agreed by the Parties to the dispute, the Parties will utilize in the arbitration the AAA’s Commercial Arbitration Rules and Mediation Procedures (including Procedures for Large, Complex Commercial Disputes) or similar rules and practices of another Arbitration Organization from time-to-time in force, except that if such rules and practices, as modified herein, conflict with New Mexico Rules of Civil Procedure or any other provisions of New Mexico law then in force that are specifically applicable to arbitration proceedings, such New Mexico laws will govern. The arbitration will be conducted at a location in Albuquerque, New Mexico, unless otherwise agreed by the affected Parties.

23.5 Decision of Arbitrators . The arbitrators will hear evidence submitted by the respective Parties or group or groups of Parties and may call for additional information, which additional information must be furnished by the Party having such information. The decision of a majority of the arbitrators (“Arbitration Award”) must be rendered no later than twenty (20) days after the conclusion of the arbitration hearing and will be binding upon all the Parties and must be based on the provisions of this Restructuring Agreement and applicable New Mexico or federal Law. The Arbitration Award must be in writing and must explain in reasonable detail the basis of the award.

23.6 Enforcement of Arbitration Award . This agreement to arbitrate is specifically enforceable, and the Arbitration Award will be final and binding upon the Parties to the extent provided by the laws of the State of New Mexico. Any Arbitration Award may be filed with a court of competent jurisdiction in New Mexico and upon motion of a Party the court shall enter a judgment in conformity therewith as provided by the New Mexico Uniform Arbitration Act. Said judgment shall be enforceable in other States and Territories of the United States under the Full Faith and Credit provisions of the United States Constitution and other Laws.

23.7 Fees and Expenses . The non-prevailing Party will be responsible for reimbursing the prevailing Party for the fees and expenses of the arbitrators, unless the Arbitration Award specifies some other apportionment of such fees and expenses. All other expenses and costs of the arbitration, including attorney fees and expert witness fees, will be borne by the Party incurring the same.

23.8 Interest and Penalty Interest . The arbitrators will award the amount of interest actually earned during deposit of the disputed amounts in the escrow account (“Escrow Interest”) to the Party who prevails in the arbitration. The arbitrators will further calculate interest on the monetary portion of the Arbitration Award at the Wall Street Journal Prime Rate (or any successor to that rate) plus five percent (5%). The arbitrators will subtract Escrow Interest from the interest calculated pursuant to the immediately preceding sentence and also award the result of that calculation (“Penalty Interest”) to the prevailing Party. The arbitrators will have no discretion to refuse to award either Escrow Interest or Penalty Interest.

23.9 Prompt Resolution . The Parties acknowledge the importance of prompt dispute resolution and will cooperate toward the rendering of an Arbitration Award no later than two hundred and seventy (270) days after the Arbitration Notice is served.

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23.10 Default . A default under this Restructuring Agreement (“Default”) will occur only if a Party (i) has received a Notice of Dispute and fails to follow the procedures in Section 23.1.2, or (ii) does not comply with all of the terms and conditions of an Arbitration Award against it (unless the effect of such Arbitration Award is stayed).

23.11 Consequences of Default . Any Party in Default under this Restructuring Agreement will lose its rights under this Restructuring Agreement, the Decommissioning Agreement (if the Decommissioning Agreement is in effect), and the Mine Reclamation Agreement so long as the Party remains in Default. This consequence of Default is in addition to and cumulative of any other remedy to which the Party in Default may be subject. If and when the Party in Default remedies the Default, its rights under such agreements will be restored.

23.12 Legal Remedies . Nothing in this Section 23 will be deemed to prevent a Party from commencing judicial action: (i) to obtain a provisional remedy to protect the effectiveness of the arbitration proceeding; (ii) to confirm, enforce, modify, correct, vacate or challenge an Arbitration Award on grounds provided for in the New Mexico Uniform Arbitration Act; (iii) to obtain relief in instances where the arbitrators are unable or unwilling to act within the time provided for in Section 23.9; or (iv) where, as the result of the unreasonable or dilatory conduct of another Party, a Party is not able to obtain a timely valid and enforceable Arbitration Award.

24. Audit Rights; Related Disputes

24.1 Right of Audit . The Operating Agent will maintain complete and accurate records of all expenses and transactions for which a Party may have cost responsibility under this Restructuring Agreement. Such records will be maintained from the date an expense is billed to a Party hereunder for a period of the longer of: (i) the expiration of the statute of limitations for actions based on contract; or (ii) the date the records may be destroyed under the Operating Agent’s document retention policy. Any Party (an “Initiating Party”) may, upon reasonable advance written notice to the Operating Agent, conduct an audit of all records, invoices, costs, expenses or Liabilities charged to the Initiating Party or for which the Initiating Party has or may have cost responsibility. Parties desiring to perform an audit will cooperate with one another so as to minimize the number of audits and any undue burden upon the Operating Agent. Each such audit will be carried out by an auditor of the Initiating Party’s choosing and at the expense of the Initiating Party, except as provided in Section 24.3. The Operating Agent will cooperate with the Initiating Party and the Initiating Party’s auditor and will make available its relevant business records at reasonable times and places, upon reasonable advance notice. A copy of the audit report will be provided to all Parties by the Initiating Party within fifteen (15) days of receipt of the audit report.

24.2 Dispute Resolution . If any Party disagrees with an audit finding from an audit conducted under Section 24.1, the Party may within fifteen (15) Business Days of the receipt of the audit report request in writing that the audit be reviewed by providing such request to all of the Parties. After any such request, the affected Parties will review the expenditure and will endeavor to agree upon whether an over- or under-billing occurred. If, after the review, the affected Parties determine that the expenditure was over- or under-billed, an adjustment to the

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billing that is the subject of the audit finding will be made to eliminate the over- or under-billing and an adjusted bill will be sent as provided for in Section 24.3. Each Party that receives a payment as a result of under- or over-billing will reimburse the Initiating Party as provided for in Section 24.3. If within thirty (30) Business Days of the date of the mailing of the written request for review the affected Parties are unable to agree in writing on a modification of the expenditure to eliminate the over- or under-billing, the matter will be submitted to dispute resolution pursuant to Section 23.

24.3 Adjusted Billing Procedures . If as the result of an audit and any related dispute resolution procedures under Section 23.1 or Section 23.2 it is determined that there was an under- or over-billing, the Operating Agent will issue invoices to correct the under- or over-billing with interest at the Wall Street Journal Prime Rate (or any successor to that rate). Interest will be calculated from the due date for payments on the prior invoices that included the under-or over-billed amounts to the date of the revised billings. The owing Party will pay any amounts owed on the corrected invoices within twenty (20) Business Days of receipt of the revised billing reflecting the result of the audit report. Each Party (other than an Initiating Party) that receives a payment or credit as a result of an audit report will reimburse the Initiating Party for the cost of the audit based on the amount received by such Party as a percentage of the total amount of payments and credits received by Parties; provided, that if the amount received by a Party is less than the lower of (i) $5,000 or (ii) ten percent (10%) of the amount of the disputed billing, no reimbursement for the audit costs will be required.

24.4 Effectiveness . The provisions of this Section 24 will become effective as of the Exit Date. Matters requiring audit arising before the Exit Date will be addressed in a manner consistent with the audit provisions of the SJPPA.

25. Miscellaneous Provisions

25.1 Governing Law . This Restructuring Agreement is made under and will be governed by New Mexico law, without regard to conflicts of law or choice of law principles that would require the application of the laws of a different jurisdiction.

25.2 Venue . Venue with respect to any judicial proceeding arising out of or relating to this Restructuring Agreement will lie exclusively in the state or federal courts in Albuquerque, New Mexico, and the Parties irrevocably consent and submit to the exclusive jurisdiction of such courts for such purpose and irrevocably waive the defense of an inconvenient forum to the maintenance of any such action or proceeding. Service of process may be made in any manner recognized by such courts. A final judgment of the state or federal court will be enforceable in other states under applicable Law.

25.3 Manner of Giving of Notice . Any notice, demand, protest or request provided for in this Restructuring Agreement, or served, given or made in connection with it, will be deemed properly served, given or made: (i) when delivered personally or by prepaid overnight courier, with a record of receipt; (ii) on the fourth day if mailed by certified mail, return receipt requested; or (iii) on the day of transmission, if sent by facsimile or electronic mail during regular business hours or the day after transmission, if sent after regular business hours (provided, however, that such

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facsimile or electronic mail will be followed on the same day or next Business Day with the sending of a duplicate notice, demand or request by a nationally recognized prepaid overnight courier with record of receipt), to the persons specified below:


25.3.1	Public Service Company of New Mexico

Attn: Vice President, PNM Generation

2401 Aztec N.E., Bldg. A

Albuquerque, NM 87107

with a copy to:

Public Service Company of New Mexico

c/o Secretary

414 Silver Ave. S.W.

Albuquerque, NM 87102


25.3.2	Tucson Electric Power Company

88 E. Broadway Blvd.

MS HQE901

Tucson, AZ 85701

Attn: Corporate Secretary


25.3.3	City of Farmington

c/o City Clerk

800 Municipal Drive

Farmington, NM 87401

with a copy to:

Farmington Electric Utility System

Electric Utility Director

101 North Browning Parkway

Farmington, NM 87401


25.3.4	M-S-R Public Power Agency

c/o General Manager

1231 11 ^th Street

Modesto, CA 95354


25.3.5	Southern California Public Power Authority

c/o Executive Director

1160 Nicole Court

Glendora, CA 91740


25.3.6	City of Anaheim

c/o City Clerk

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200 South Anaheim Boulevard

Anaheim, CA 92805

with a copy to:

Public Utilities General Manager

201 South Anaheim Boulevard

Suite 1101

Anaheim, CA 92805

25.3.7 Incorporated County of

Los Alamos, New Mexico

c/o County Clerk

1000 Central Ave.

Suite 240

Los Alamos, NM 87544

with a copy to:

Incorporated County of

Los Alamos, New Mexico

c/o Utilities Manager

1000 Central Ave.

Suite 130

Los Alamos, NM 87544


25.3.8	Utah Associated Municipal Power Systems

c/o General Manager

155 North 400 West

Suite 480

Salt Lake City, UT 84103


25.3.9	Tri-State Generation and Transmission

Association, Inc.

c/o Chief Executive Officer

1100 West 116 ^th Avenue

Westminster, CO 80234

Or P. O. Box 33695

Denver, CO 80233

For purposes of overnight courier service, Tri-State’s address will be:

Tri-State Generation and Transmission Association, Inc.

c/o Chief Executive Officer

3761 Eureka Way

Frederick, CO 80516

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25.3.10	PNMR Development and Management Corporation

c/o Corporate Secretary

PNM Resources

Corporate Headquarters

414 Silver Ave. SW

Albuquerque, NM 87158-1245

A Party may, at any time or from time-to-time, by written notice to the other Parties, change the designation or address of the person so specified as the one to receive notices pursuant to this Restructuring Agreement.

25.4 Other Documents . Each Party agrees, upon request of another Party, to make, execute and deliver any and all documents and instruments reasonably required to carry into effect the terms of this Restructuring Agreement; provided, that such documents and instruments will not increase or expand the obligations of a Party hereunder.

25.5 Incorporation of Exhibits . All exhibits attached to, or referred to in, this Restructuring Agreement are incorporated in this Restructuring Agreement by this reference.

25.6 Captions and Headings . The captions and headings appearing in this Restructuring Agreement are inserted merely to facilitate reference and will have no bearing upon the interpretation of the provisions hereof.

25.7 Prior Obligations Unaffected . Except as otherwise provided herein, nothing in this Restructuring Agreement will be deemed to relieve the Parties of their obligations in effect prior to the Effective Date and such obligations will continue in full force and effect until satisfied or as otherwise mutually agreed.

25.8 Amendment and Modification . Except as otherwise provided herein, this Restructuring Agreement may be amended, modified or supplemented only by written instrument executed by all of the Parties with the same formality as this Restructuring Agreement.

25.9 Waivers of Compliance . Except as otherwise provided herein, any failure by a Party to comply with any obligation, covenant, agreement or condition of this Restructuring Agreement may be waived by the Party entitled to the benefits thereof only by written instrument signed by the Party granting such waiver, but such waiver or failure to insist upon strict compliance with such obligation, covenant, agreement or condition will not operate as a waiver of, or estoppel with respect to, any earlier or subsequent or other failure.

25.10 Uncontrollable Forces . No Party will be considered to be in default in the performance of any of its obligations hereunder (other than obligations of a Party to pay costs and expenses) if failure of performance is due to Uncontrollable Forces. The term “Uncontrollable Forces” means any cause beyond the control of the Party affected, including failure of facilities, flood, earthquake, storm, fire, lightning, epidemic or pandemic, war, riot,

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civil disturbance, labor dispute, sabotage or terrorism, restraint by court order or public authority, or failure to obtain approval from a necessary Governmental Authority which by exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by exercise of due diligence it is unable to overcome. Nothing contained herein requires a Party to settle any strike or labor dispute in which it may be involved. Any Party rendered unable to fulfill any obligation by reason of Uncontrollable Forces will promptly provide notice to the other Parties and will exercise due diligence to remove such inability with all reasonable dispatch.

25.11 No Interpretation against Drafter . This Restructuring Agreement has been drafted with full participation by all of the Parties and their counsel of choice and no provision hereof will be construed against any Party on the ground that such Party or its counsel was the author of such provision. All of the provisions of this Restructuring Agreement will be construed in a reasonable manner to give effect to the intentions of the Parties in executing this Restructuring Agreement.

25.12 No Third Party Beneficiaries . The terms and provisions of this Restructuring Agreement are intended solely for the benefit of the Parties and their respective successors and permitted assigns, and it is not the intention of the Parties to confer third-party beneficiary rights upon any other person.

25.13 Compliance with Law. The Parties will comply with all applicable Laws in the performance of their respective obligations under this Restructuring Agreement.

25.14 Independent Covenants . The covenants and obligations contained in this Restructuring Agreement are independent covenants, not dependent covenants, and the obligation of a Party to perform all of the obligations and covenants to be by it kept and performed is not conditioned on the performance by another Party of all of the covenants and obligations to be kept and performed by it. Nothing in this Section 25.14 affects the rights of the Parties under the dispute resolution and default provisions of Section 23.

25.15 Invalid Provisions . If any provision of this Restructuring Agreement is held to be illegal, invalid or unenforceable under any present or future Law, and if the rights or obligations of any Party under this Restructuring Agreement will not be materially and adversely affected thereby, such provision will be fully severable, this Restructuring Agreement will be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof, the remaining provisions of this Restructuring Agreement will remain in full force and effect and will not be affected by the illegal, invalid or unenforceable provision or by its severance herefrom, and the Parties will negotiate in good faith to attempt to agree upon a legal, valid and enforceable provision as similar in terms to such illegal, invalid or unenforceable provision as may be possible.

25.16 Parties’ Cost Responsibilities . Each Party will be solely responsible for its own costs and expenses, including fees and costs of counsel, incurred in connection with the negotiation of this Restructuring Agreement and with any actions associated with the implementation of this Restructuring Agreement, including obtaining Regulatory Approvals.

51 Restructuring Agreement 7/31/2015

EXECUTION VERSION

25.17 Entire Agreement . This Restructuring Agreement, together with the schedules and exhibits hereto, supersedes all prior negotiations, agreements and understandings between the Parties with respect to the covenants and obligations agreed upon in this Restructuring Agreement.

25.18 Survival of Certain Provisions . Termination of this Restructuring Agreement will not relieve a Party of any obligation or liability incurred by such Party before and existing as of the Termination Date, or any obligations resulting from such Party’s Default hereunder.

25.19 No Admission of Liability . The terms of this Restructuring Agreement are the product of compromise between and among the Parties. Neither any conduct nor statements made in its negotiation, nor entry by the Parties into it, will constitute evidence of, or an admission of, liability; provided, however, nothing in this Section 25.19 will be construed or interpreted to excuse any Party from, or be used by any Party to argue against, that Party’s performance of any of its obligations under this Restructuring Agreement.

25.20 Other Rights . Subject to Sections 20.14, 23.1.3 and 23.12, the rights and remedies provided in this Restructuring Agreement will be in addition to any other rights and remedies the non-defaulting Parties have in law or equity.

25.21 Execution in Counterparts . This Restructuring Agreement may be executed in any number of counterparts, and each executed counterpart will have the same force and effect as an original instrument as if all the Parties to the aggregated counterparts had signed the same instrument. Any signature page of this Restructuring Agreement may be detached from any counterpart thereof without impairing the legal effect of any signatures thereon and may be attached to any other counterpart of this Restructuring Agreement identical in form thereto but having attached to it one or more additional pages. Electronic or pdf signatures will have the same effect as an original signature.

IN WITNESS WHEREOF , the Parties have caused this Restructuring Agreement to be executed on their behalf and the signatories hereto represent that they have been duly authorized to enter into this Restructuring Agreement on behalf of the Party for whom they sign.

[Signatures on succeeding pages]

52 Restructuring Agreement 7/31/2015

EXECUTION VERSION

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _ /s/ Chris M. Olson ______________

Its: __ __Vice President - Generation _____

Date: __ June 30, 2015_______________

TUCSON ELECTRIC POWER COMPANY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE CITY OF FARMINGTON, NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

M-S-R PUBLIC POWER AGENCY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

By: ________________________________

Its: ________________________________

Date: ______________________________

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

By: _______________________________

Its: _______________________________

Date: _____________________________

CITY OF ANAHEIM

By: _______________________________

Its: _______________________________

Date: _____________________________

54 Restructuring Agreement 7/31/2015

EXECUTION VERSION

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

TUCSON ELECTRIC POWER COMPANY

By: _ /s/_Mark Mansfield _ _____________

Its: ___ Vice President, Energy Resources__

Date: _______ 7/1/15 _____________

THE CITY OF FARMINGTON, NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

M-S-R PUBLIC POWER AGENCY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

By: ________________________________

Its: ________________________________

Date: ______________________________

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

By: _______________________________

Its: _______________________________

Date: _____________________________

CITY OF ANAHEIM

By: _______________________________

Its: _______________________________

Date: _____________________________

54 Restructuring Agreement 7/31/2015

EXECUTION VERSION

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

TUCSON ELECTRIC POWER COMPANY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE CITY OF FARMINGTON, NEW MEXICO

By: _ /s/ _ Robert Mayes________________

Its: __ City Manager __________________

Date: _______ 7/1/15 _________________

M-S-R PUBLIC POWER AGENCY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

By: ________________________________

Its: ________________________________

Date: ______________________________

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

By: _______________________________

Its: _______________________________

Date: _____________________________

CITY OF ANAHEIM

By: _______________________________

Its: _______________________________

Date: _____________________________

54 Restructuring Agreement 7/31/2015

EXECUTION VERSION

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

TUCSON ELECTRIC POWER COMPANY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE CITY OF FARMINGTON, NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

M-S-R PUBLIC POWER AGENCY

By: _ /s/_Martin Hopper _____________

Its: __ General Manager ______________

Date: _ 7-27-15 _________________

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

By: ________________________________

Its: ________________________________

Date: ______________________________

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

By: _______________________________

Its: _______________________________

Date: _____________________________

CITY OF ANAHEIM

By: _______________________________

Its: _______________________________

Date: _____________________________

54 Restructuring Agreement 7/31/2015

EXECUTION VERSION

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

TUCSON ELECTRIC POWER COMPANY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE CITY OF FARMINGTON, NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

M-S-R PUBLIC POWER AGENCY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

By: _ /s/ Kristin Henderson ____________

Its: _ Council Chair _________________

Date: _ July 28, 2015 __________________

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

By: _______________________________

Its: _______________________________

Date: _____________________________

CITY OF ANAHEIM

By: _______________________________

Its: _______________________________

Date: _____________________________

54 Restructuring Agreement 7/31/2015

EXECUTION VERSION

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

TUCSON ELECTRIC POWER COMPANY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE CITY OF FARMINGTON, NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

M-S-R PUBLIC POWER AGENCY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

By: ________________________________

Its: ________________________________

Date: ______________________________

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

By: _/s/ Fred Mason__________________

Its: ___ President____________________

Date: _ 7- 16-2015___________________

CITY OF ANAHEIM

By: _______________________________

Its: _______________________________

Date: _____________________________

54 Restructuring Agreement 7/31/2015

CALIFORNIA ALL-PURPOSE ACKNOWLEDGMENT

CIVIL CODE § 1189

State of California )

County of ____ Los Angeles ___________________)

On __ July 16, 2015 _________before me, _________ Salpi Ortiz, a notary public ________________ , Date Here Insert Name and Title of the Officer

personally appeared _______ Fred Mason ___________________________________

Name(s) of Signer(s)

____________________________________________________________________________________

who proved to me on the basis of satisfactory evidence to be the person(s) whose name(s) is/are subscribed to the within instrument and acknowledged to me that he/she/they executed the same in his/her/their authorized capacity(ies), and that by his/her/their signature(s) on the instrument the person(s), or the entity upon behalf of which the person(s) acted, executed the instrument.

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

Signature_ /s/Salpi Ortiz _________

Signature of Notary Public

Place Notary Seal Above

-----------------------------------------------------------------OPTIONAL----------------------------------------------------------

Though this section is optional, completing this information can deter alteration of the document or fraudulent reattachment of this form to an unintended document.

Description of Attached Document

Title or Type of Document:_________________________ Document Date: ___ ______ ______

Number of Pages: _______ Signer(s) Other Than Named Above: ______________________________

Capacity(ies) Claimed by Signer(s)



□Signer's Name:_____________________	□Signer's Name:_____________________
□Corporate Officer ___ Title(s):_________	□Corporate Officer ___ Title(s):_________
□Partner - □Limited □General	□Partner - □Limited □General
□Individual □Attorney in Fact	□Individual □Attorney in Fact
□Trustee □Guardian or Conservator	□Trustee □Guardian or Conservator
□Other: ____________________________	□Other: ____________________________
Signer Is Representing: _______________	Signer Is Representing: _______________
__________________________________	__________________________________

EXECUTION VERSION

PUBLIC SERVICE COMPANY OF NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

TUCSON ELECTRIC POWER COMPANY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE CITY OF FARMINGTON, NEW MEXICO

By: _______________________________

Its: _______________________________

Date: _____________________________

M-S-R PUBLIC POWER AGENCY

By: _______________________________

Its: _______________________________

Date: _____________________________

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

By: ________________________________

Its: ________________________________

Date: ______________________________

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

By: _______________________________

Its: _______________________________

Date: _____________________________

CITY OF ANAHEIM

APPROVED AS TO FORM:

MICHAEL R.W. HOUSTON, CITY ATTORNEY

By: __/s/_Dukku Lee_______________ BY ________ _/s/ Alison M. Kott 7-27-15___

Dukku Lee Alison M. Kott, Assistant City Attorney

Public Utilities General Manager

Date: July 27, 2015

54 Restructuring Agreement 7/31/2015

EXECUTION VERSION

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By: __/s/ Douglas Hunter_______________

Its: ___ General Manager______________

Date: _ July 31, 2015 _________________

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

By: _______________________________

Its: _______________________________

Date: _____________________________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By: __________________________________

Its: __________________________________

Date: ________________________________

55 Restructuring Agreement 7/31/2015

EXECUTION VERSION

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By: _______________________________

Its: _______________________________

Date: _____________________________

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

By: __/s/_Micheal McInnes_ ____________

Its: ____ CEO________

Date: ___ 7-22-15_____ ____________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By: __________________________________

Its: __________________________________

Date: ________________________________

55 Restructuring Agreement 7/31/2015

EXECUTION VERSION

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By: _______________________________

Its: _______________________________

Date: _____________________________

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

By: _______________________________

Its: _______________________________

Date: _____________________________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By: _ /s/ Elisabeth Eden_____ ____________

Its: _ President, Chief Executive Officer and Treasurer

Date: _June 30, 2015 ___________________

55 Restructuring Agreement 7/31/2015

EXECUTION VERSION

EXHIBIT A

Regulatory Approvals

The Parties have identified the following Regulatory Approvals required in connection with this Restructuring Agreement:


A.	Public Service Company of New Mexico


a.	New Mexico Public Regulation Commission


i.	Approval for abandonment of interests in Unit 2 and Unit 3 pursuant to NMSA 1978, § 62-9-5;


ii.	A certificate of public convenience and necessity pursuant to NMSA 1978, § 62-9-1 to own and operate Unit 4 with a greater ownership interest.


b.	Federal Energy Regulatory Commission


i.	Approvals for the transfer of ownership interests in jurisdictional assets pursuant to Section 203 of the Federal Power Act.


ii.	Approvals pursuant to Section 205 of the Federal Power Act.


B.	Tucson Electric Power Company

None


C.	City of Farmington, New Mexico

None


D.	M-S-R Public Power Agency

None


E.	County of Los Alamos

None


F.	Southern California Public Power Agency

None


G.	City of Anaheim

None

A-1

EXECUTION VERSION


H.	Utah Associated Municipal Power Systems

None


I.	Tri-State Generation and Transmission Association, Inc.

None


J.	PNMR Development and Management Corporation

Federal Energy Regulatory Commission


i.	Approvals for the transfer of ownership interests in jurisdictional assets pursuant to Section 203 of the Federal Power Act.

A-2

EXECUTION VERSION

EXHIBIT B

Other Project Agreements

The Parties have identified the following Other Project Agreements:



Contract Title	Contract Date	Contract Parties
Amended and Restated San Juan Project Participation Agreement	3/23/2006	San Juan Participants
San Juan Project Designated Representative Agreement and amendment No. 1 thereto	4/29/1994; 10/31/2000	San Juan Participants
San Juan Project Operating Procedure No. 1, Energy Accounting under SJ Project Participation Agreement	10/11/2000	San Juan Participants
Mine Reclamation and Trust Funds Agreement	6/1/2012	San Juan Participants
San Juan Unit 3 Purchase Agreement	3/25/1993	Century Power and SCPPA
San Juan Unit 3 Purchase Agreement	6/1/1994	Century Power and Tri-State
1 ^st Amendment to the San Juan Unit 3 Purchase Contract	5/20/1993	Century Power Corporation and Southern California Public Power Authority
Amended and Restated Interconnection Agreement	10/7/1992	Tucson Electric Power and Century
Assignment and Amendment to Amended and Restated Interconnection Agreement	3/1/1993	Tucson Electric Power and Century Power Corporation
San Juan Unit 4 Purchase and Participation Agreement and Amendment No. 1	4/26/1991 and 10/27/1999	PNM and Anaheim
Instrument of Sale and Conveyance	8/12/1993	PNM and Anaheim
Insurance Policy endorsements adding Anaheim as named insured on SJ Project insurance policies	8/12/1993	PNM and Anaheim
Assumption Agreement (Pollution Control Bond Operation, Maintenance and Insurance Covenants)	8/12/1993	PNM and Anaheim
Interconnection Agreement	4/26/1991	PNM and Anaheim

B-1

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Letters to Anaheim from PNM re: exchange of economy energy under Service Schedule C of the Interconnection Agreement dated 4/26/1991	5/22/1992; 5/19/2003	PNM and Anaheim
Interconnection Agreement, Service Schedule E, Interruptible Transmission Service	4/26/1991	PNM and Anaheim
Interconnection Agreement, Service, Schedule F, San Juan Unit 4 Transmission Service	4/26/1991	PNM and Anaheim
Operating Procedure No. 1 under the Purchase and Participation Agreement	12/27/1995	PNM and Anaheim
Letter to PNM from Anaheim (notice of intent to become CAISO member)	6/20/2002	PNM and Anaheim
Recovery System Water Agreement	8/31/2012	PNM and BHP Navajo Coal Co
Water Use Agreement Amendment 1 Amendment 2	12/1/2009 10/26/2011 6/1/2013	PNM and BHP Navajo Coal Co
Amended Instrument of Sale and Conveyance (Installment Sale Agreement; pollution control systems) (PNM grantee, Farmington, grantor)	5/16/1979	PNM and Farmington
Amended Instrument of Sale and Conveyance (Installment Sale Agreement; pollution control systems) (PNM grantor, Farmington grantee)	5/16/1979	PNM and Farmington
Purchase Agreement and Participation Agreement and amendments 1 and 2 thereto	11/17/1981; 10/31/1984 & 10/27/1999	PNM and Farmington
Instrument of Sale and Conveyance	11/17/1981	PNM and Farmington
Insurance (adding Farmington to Project insurance policies)	11/1981	PNM and Farmington
First Amended and Restated Interconnection Agreement	6/19/2007	PNM and Farmington
First Amended and Restated Construction and Interconnection Agreement	6/19/2007	PNM and Farmington
Operating Procedure No. 1 for Hazard Sharing Obligation, Rev. 2, in conjunction with Service Schedule E of Interconnection Agreement	5/31/2007	PNM and Farmington
Operating Procedure No. 2 for Blackstart Restoration Plan, Rev. 2, in conjunction with Interconnection Agreement dated 11/17/1981	5/31/2007	PNM and Farmington

B-2

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Operating Procedure No. 3 for Normal and Emergency Operation of the Hogback Substation	6/7/2007	PNM and Farmington
Operating Procedure No. 4 for Notification of Maintenance or Testing	6/7/2007	PNM and Farmington
Operating Procedure No. 5 for Clearance and Switching Coordination Agreement (First Amended and Restated Interconnection Agreement)	6/7/2007	PNM and Farmington
San Juan to Shiprock Transmission System Participation Agreement	5/24/1982	PNM and Farmington
Managed Business Relationship Agreement	7/1/2004	PNM and GE
Water Supply Agreement	7/17/2000	PNM and Jicarilla Apache Tribe
Amended and Restated San Juan Unit 4 Purchase and Participation Agreement and Amendment No. 1 thereto	12/28/1984 and 10/27/1999	PNM and Los Alamos County
Instrument of Sale and Conveyance	7/1/1985	PNM and Los Alamos County
Los Alamos County added as additional insured on Project insurance policies	7/1/1985	PNM and Los Alamos County
Interconnection Agreement	11/26/1984	PNM and Los Alamos County
Interconnection Agreement, Service Schedule A, Emergency Generation Service	11/26/1984	PNM and Los Alamos County
Interconnection Agreement, Service Schedule B, Economy Energy Interchange	11/26/1984	PNM and Los Alamos County
Interconnection Agreement, Service Schedule C, Hazard Sharing	11/26/1984	PNM and Los Alamos County
Interconnection Agreement, Service Schedule G, Transmission Service through the Norton 115 KV Switching Station	11/26/1984	PNM and Los Alamos County
Third Revised Service Agreement for Network Integration Transmission Service	7/3/2012	PNM and Los Alamos County
Third Revised Network Operating Agreement	7/3/2012	PNM and Los Alamos County
Agreement of the Operating Committee (cost sharing of telemetry and data acquisition at SJ Units 3 and 4, SJ Switching Station) (supersedes 2 operating committee agreements dated 7/11/1985)	7/22/1986	PNM and Los Alamos County
PNM-LAC Operating Procedure Number II, Substitute Energy	5/1/1991	PNM and Los Alamos County

B-3

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Operating Procedure Number III, Hazard Sharing obligation, Service Schedule C of Interconnection Agreement (SJ Units 3 and 4)	9/29/1992	PNM and Los Alamos County
PNM-LAC Operating Procedure Number IV, Area Control Accounting (Service Schedule H) (entitlement to SJ generation)	5/1/1991	PNM and Los Alamos County
Operating Procedure Number V, Determination of Credit for Self Supply of Reactive Supply & Voltage Control Service from Generation Sources (attachment refers to SJ Ratio)	9/20/1999	PNM and Los Alamos County
Replacement for the Revised & Restated Operating Procedure No. VI, Energy Imbalance Accounts & Derivation of Monthly Invoices (SJ Station)	7/26/2002	PNM and Los Alamos County
Letter Agreement between PNM and Incorporated Los Alamos County of Los Alamos re: defining and agreeing on interruptible schedules (San Juan)	4/16/1998	PNM and Los Alamos County
Interconnection Agreement	9/26/1983	PNM and M-S-R
San Juan Unit 4 Early Purchase and Participation Agreement, as amended	9/26/1983; 12/16/1987; 10/31/1989; 10/27/1999	PNM and M-S-R
Instrument of Sale and Conveyance	12/31/1983	PNM and M-S-R
Certificate of Insurance	12/28/1983	PNM and M-S-R
Interconnection Agreement, Service Schedule A, Economy Energy Interchange (SJ Units 3 and 4)	9/26/1983	PNM and M-S-R
Amendment No. 1 to Service Schedule A, to the Interconnection Agreement (to permit seller to offer economy energy at current market price or actual costs to generate energy)	1/22/1986	PNM and M-S-R
SSB - Economy Energy Brokerage	9/26/1983	PNM and M-S-R
SSC - Power Exchange	9/26/1983	PNM and M-S-R
San Juan Unit 4 Operating Procedure No. 1	4/25/1995	PNM and M-S-R
Coal Feedstock Purchase Agreement	6/21/2013	PNM and San Juan Fuels, LLC
Pre-Closing Coal Inventory Purchase Agreement	6/21/2013	PNM and San Juan Fuels, LLC
Refined Coal Supply Agreement	6/21/2013	PNM and San Juan Fuels, LLC
Surface Use Lease Agreement	1/1/2003	PNM and SJCC
Water Use Agreement - SJCC Pit Dewatering	4/24/1989	PNM and SJCC
Purchase Agreement	5/16/1979	PNM and TEP

B-4

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Instrument of Sale and Conveyance	5/16/1979	PNM and TEP
Tucson Assignment	5/16/1979	PNM and TEP
Amended Interconnection Agreement	12/19/1997	PNM and TEP
Amendment No. 1 to the Amended Interconnection Agreement	7/13/1998	PNM and TEP
Amendment No. 2 to the Amended Interconnection Agreement	1/1/2003	PNM and TEP
Amendment No. 3 to the 1997 Amended Interconnection Agreement	3/14/2007	PNM and TEP
Amended Interconnection Agreement, Service Schedule A - Reserve Sharing, Exhibit 1 - Revised 2009 (Springerville Unit)	1/1/2009	PNM and TEP
Letter to Tucson Electric from PNM re: agreement for SJGS Curtailment Energy Sales (1/25/1979 Interconnection Agreement)	4/26/1982	PNM and TEP
Power Exchange and Transmission Agreement (SJGS, SJ 345kV Switchyard), as amended	4/26/1982; 10/12/2006	PNM and TEP
Network Interface Control Document (power control systems data exchange)	9/23/1985	PNM and TEP
Assignment of Water Contract (delivery of 20,200 acre feet of water per annum)	12/1/2009	PNM and TEP
Fourth Revised Service Agreement for Network Integration Transmission Service	7/31/2006	PNM and Tri-State
Fourth Revised Operating Agreement	7/31/2006	PNM and Tri-State
Schedule of Tri-State Generation and Transmission Assoc Network Resources (SJ Unit 3)	8/26/2010	PNM and Tri-State
Operating Procedures Agreement, Contract No. TS-00-0020, with Operating Agreement Nos. 1 through 6 (signed 2/2001) re: adoption of operating procedures between PNM/Plains subsequent to merger of Plains and Tri-State to provide SCADA for PNM assets purchased from Plains.	7/1/2000	PNM and Tri-State
Revision 2 to Operating Procedure 06, Real Time Metering Data and Equipment Status to be Exchanged (SJ Units 3 & 4)	1/31/2007	PNM and Tri-State
Operating Procedure 03, Restoration and Operating Guidelines (San Juan-Ojo 345kV line)	8/7/2008; 1/30/2010	PNM and Tri-State
Operating Procedure 8 rev 5 - Tri-State Load Within PNM Balancing Authority	1/1/2013	PNM and Tri-State
Operating Procedure 10 - Energy Imbalance accounts & Derivations of Monthly Invoices, under Specification 4 of the Service Agreement for Network Integration Transmission Service (SJGS)	2/28/2001	PNM and Tri-State

B-5

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Op Proc No 11 Defining the Methodology for Determination of a Credit for Tri-State’s Reactive Supply (attachment re: San Juan)	2/28/2001	PNM and Tri-State
First Revised Op Proc No 12 Rev 1 Reserve Methodology Activation and Scheduling, under First Revised Reserve Obligation Agreement effective 10/1/04	9/27/2004	PNM and Tri-State
Op Proc No 13 Pyramid Generating Station Deliveries (ALIS), under Second Revised Service Agreement for Network Integration Transmission Service dated 4/1/2003 (San Juan 345kV)	1/1/2013	PNM and Tri-State
Op Proc No 14 Hourly Check-Out (of key energy schedules and meter data), under Network Service Agreement (PNM Control Area)	5/1/2004	PNM and Tri-State
Op Proc No 15 After the Fact Check-Out (of key energy schedules and meter data), under network integration transmission service agreement (NITSA) in PNM Control Area)	5/1/2004	PNM and Tri-State
Restoration and Operating Guidelines 03-02 Western New Mexico Area 115kV Line Overloads (San Juan-BA 345kV Line listed as a probable contingency)	5/27/2010	PNM and Tri-State
Instrument of Sale and Conveyance	1/2/1996	Century and Tri-State
Assignment and Assumption Agreement	1/2/1996	Century and Tri-State
Assignment and Assumption of Easement and License	1/2/1996	Century and Tri-State
Assignment and Amendment No. 2 to Amended and Restated Interconnection Agreement	1/2/1996	TEP, Century, SCPPA and Tri-State
Assignment and Amendment No. 2 to Assumption Agreement	1/2/1995	TEP, Century, SCPPA and Tri-State
Delegation Agreement and Acknowledgment	6/18/2007	All San Juan Participants
Various Letter Agreements	1/13/98, 1/29/1999, 1/1/2000, 1/24/2001, 1/1/2002, 2/12/2003, 1/31/2004, 1/7/2005, and 2/13/2006	PNM, TEP, Los Alamos, Farmington, MSR, SCPPA, Anaheim, UAMPS and Tri-State

B-6

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Contract No. TS-99-0035 for Purchase of Firm Power (SJ 345kV Bus)	7/1/2000	PNM and Tri-State
Restated and Amended San Juan Unit 4 Purchase and Participation Agreement and Amendment No. 1 thereto	5/27/1993 and 10/27/1999	PNM and UAMPS
Instrument of Sale and Conveyance	6/2/1994	PNM and UAMPS
PNM Certificate adding UAMPS as named insured on all San Juan Project Insurance Policies	6/2/1994	PNM and UAMPS
Assumption Agreement (assumes PNM's obligations for PCB Operation, Maintenance and Insurance Covenants under ISAs)	6/2/1994	PNM and UAMPS
Interconnection Agreement	5/27/1993	PNM and UAMPS
Service Schedule A to Interconnection Agreement, Emergency Assistance	5/27/1993	PNM and UAMPS
Service Schedule B, to Interconnection Agreement Banked Energy	5/27/1993	PNM and UAMPS
Service Schedule C to Interconnection Agreement, Short Term Firm Capacity	5/27/1993	PNM and UAMPS
Amendment Number One to Service Schedule C to Interconnection Agreement	11/12/1993	PNM and UAMPS
Service Schedule D to Interconnection Agreement, Interruptible Transmission Service	5/27/1993	PNM and UAMPS
Amendment Number One to Service Schedule D to Interconnection Agreement	11/12/1993	PNM and UAMPS
Service Schedule E to Interconnection Agreement, San Juan Unit 4 Transmission Service	5/27/1993	PNM and UAMPS
Amended Number One to Service Schedule E to Interconnection Agreement	7/20/1994	PNM and UAMPS
Operating Procedure Number 1 re: scheduling of UAMPS SJ Unit 4 entitlement pursuant to Section 12 of the Purchase and Participation Agreement	5/31/1994	PNM and UAMPS
The Further Assurance Agreement (with regard to certain costs and liabilities arising in future re: contamination of soil or groundwater allocable to PNM ownership prior to purchase)	5/20/1994	PNM and UAMPS
Non-Exclusive Technology License Agreement	6/21/2013	PNM and VRC Technology, LLC
Easement and License	8/12/1993	PNM, TEP, and Anaheim

B-7

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Easement and License	11/17/1981	PNM, TEP, and Farmington
Easement and License	7/1/1985	PNM, TEP, and Los Alamos County
Easement and License	12/31/1983	PNM, TEP, and M-S-R
Low Water Weir Lease	7/9/1971	PNM, TEP, and Navajo Tribe of Indians
Environmental Indemnity Agreement	6/21/2013	PNM, TEP, and San Juan Fuels, LLC
License and Access Agreement	6/21/2013	PNM, TEP, and San Juan Fuels, LLC
Underground Coal Sales Agreement; Amendments 1, 2, 3, 4, 5	8/31/2001; 12/15/2003; 9/15/2004; 5/11/2005; 3/7/2007; 12/21/2007	PNM, TEP, and SJCC
Closing Agreement (Amendment One to Underground Coal Sales Agreement)	12/15/2003	PNM, TEP, and SJCC
Letter Agreement (Reimbursement of taxes and royalties under the Underground Coal Sales Agreement)	12/15/2003	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 1 - Post Retirement Medical Benefits (FAS-106) Settlement Agreement	4/29/2005	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 8 - Operating Cost Treatment for SJCC Asset Disposal	1/1/2006	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 2 - Operating Cost Clarification	11/28/2006	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 4 - Settlement of 2007 Issues	12/21/2007	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 5 - Revision of Base Year for Implicit Price Deflator, Gross Domestic Product	8/10/2009	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 6 - Accounting Guidance Regarding Labor and Services to Install Fixed Assets Underground	12/1/2009	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 7 - Settlement and Future Treatment of Gatebelt Drive Installation Costs	12/1/2009	PNM, TEP, and SJCC

B-8

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
UG-CSA Joint Committee Resolution Number 9 - Extension of Operating Cost Definition for Third Party Audit to years 2006-2009	7/30/2010	PNM, TEP, and SJCC
UG-CSA Joint Committee Resolution Number 10 - Costs Arising from Sierra Club's December 2009 RCRA and SMCRA Notice of Intent Letters and Sierra Club's April 8, 2010 Complaint	7/30/2010	PNM, TEP, and SJCC
Coal Combustion Byproduct Disposal Agreement Closing Agreement	1/1/2008	PNM, TEP, and SJCC
Coal Combustion Byproduct Disposal Agreement	1/1/2008	PNM, TEP, and SJCC
Easement (grant of easement to SJCC) (undated but in file with 3/10/89 Water Use Agreement)	3/10/1989	PNM, TEP, and SJCC
Refined Coal Facility Agreement	1/1/2012	PNM, TEP, and TCG Global, LLC
Easement and License	6/2/1994	PNM, TEP, and UAMPS
Grant of Authority	8/18/1980	PNM, TEP, and Utah International Inc.
Payment Allocation and Process Agreement Jicarilla Agreement	9/14/2007	PNM; APS; BHP Navajo Coal Company
Letter Agreement	3/28/1996	PNM; BHP Navajo Coal Co; BHP Minerals International, Inc.
Recommendations for San Juan River Operations and Administration for 2013 through 2016	7/2/2012	PNM; BHP; APS; Navajo Nation
Water Supply Agreement	3/2/2007	PNM; Jicarilla Apache Nation; APS; BHP Navajo Coal Company
Installment Sale Agreement (air and water pollution control facilities at San Juan Generation Station)	11/1/1977	TEP and Farmington
Installment Sale Agreement (air and water pollution control facilities at San Juan Generation Station)	1/1/1978	TEP and Farmington
Amendment No. 1 to Installment Sale Agreement	5/16/1979	TEP and Farmington
Amendment No. 2 to Installment Sale Agreement	5/16/1979	TEP and Farmington

B-9

EXECUTION VERSION



Contract Title	Contract Date	Contract Parties
Agreement (Installment Sale Agreement; pollution control systems facilities to be acquired, constructed and installed at San Juan Generating Station)	5/16/1979	TEP and Farmington
San Juan Unit No. 4 Sale of Option Agreement	11/29/1982	TEP and M-S-R
Assignment of Option by TEP	11/29/1982	TEP and M-S-R
Instrument of Sale and Conveyance by TEP	11/29/1982	TEP and M-S-R
Title Commitment re: Interest created by Easement and License	5/27/1994 (land) 6/2/1994 (easement)	UAMPS (In favor of)
Fuel and Capital Funding Agreement	09/2014	All Participants
Capacity Option and Funding Agreement	05/2015	PNM, PNMR, PNMR-D, Anaheim and M-S-R

B-10

EXECUTION VERSION

EXHIBIT C

Form of Instrument of Sale and Conveyance

[Exiting Participant], a ___________ (“____________”), in consideration of the mutual covenants and agreements contained in that certain San Juan Project Restructuring Agreement dated as of ________, 2015 (the “Restructuring Agreement”), which Restructuring Agreement is incorporated herein by this reference, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, hereby grants, transfers, bargains, sells and conveys to [Acquiring Participant], a ____________ (“________”), all of its rights, titles and interests consisting of an undivided _________% of the Ownership Interest (as defined in the Restructuring Agreement) previously conveyed to [Exiting Participant] in that certain Instrument of Sale and Conveyance (the “Original Instrument”) granted by [Grantor] to [Exiting Participant] dated [___________] and recorded in the Records of the County Clerk of San Juan County, New Mexico on [__________] in Book ____, Page _____ (“Conveyed Assets”), including all subsequent changes, additions, improvements, substitutions and accessions to the Conveyed Assets. Capitalized terms used in this document have the meaning as defined in the Restructuring Agreement unless specifically defined herein.

1. This Instrument of Sale and Conveyance is intended to, and does include all of [Exiting Participant’s] rights, titles and interests in and to all fixtures which are part of or related to the Conveyed Assets situate upon the real property described in the Original Instrument, but is not intended to and does not convey title to the underlying real property described in the Original Instrument.

2. [Exiting Participant] represents and warrants to [Acquiring Participant] and [Acquiring Participant’s] authorized successors, trustees and representatives that the Conveyed Assets are free from all encumbrances made by [Exiting Participant] and that [Exiting Participant] shall warrant and defend the same to [Acquiring Participant] and its authorized successors and assigns forever against the lawful claims and demands of all persons claiming by, through or under [Exiting Participant], but against none other. Such representation and warranty by [Exiting Participant] are subject to the following disclaimer:

EXCEPT AS OTHERWISE PROVIDED HEREIN: (1) THE CONVEYED ASSETS ARE CONVEYED BY [EXITING PARTICIPANT] TO [ACQUIRING PARTICIPANT] ON AN “AS IS,” “WHERE IS” AND “WITH ALL FAULTS” BASIS; (2) [EXITING PARTICIPANT] MAKES NO REPRESENTATION OR WARRANTY WHATSOEVER, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY REPRESENTATION OR WARRANTY AS TO THE VALUE, QUANTITY, CONDITION, SALABILITY, OBSOLESCENCE, MERCHANTABILITY, FITNESS OR SUITABILITY FOR USE OR WORKING ORDER OF, ALL OR ANY PART OF THE CONVEYED ASSETS; AND (3) [EXITING PARTICIPANT] DOES NOT REPRESENT OR WARRANT THAT THE USE OR OPERATION OF THE CONVEYED ASSETS WILL NOT VIOLATE OR CONFLICT WITH PATENT, TRADEMARK OR SERVICE MARK RIGHTS OF ANY THIRD PARTY. [ACQUIRING PARTICIPANT] ACCEPTS THE CONVEYANCE OF CONVEYED ASSETS IN ACCORDANCE WITH THE TERMS AND CONDITIONS OF THE RESTRUCTURING AGREEMENT.

C-1

EXECUTION VERSION

3. NOTWITHSTANDING THE FOREGOING, [Acquiring Participant] shall have the benefit, in proportion to its interest in the Conveyed Assets, of all manufacturers’ and vendors’ warranties (to the extent [Exiting Participant] may have a right or benefit thereof) in connection with the Conveyed Assets.

4. NOTWITHSTANDING THE FOREGOING, (i) [Exiting Participant] covenants and warrants that title to the Conveyed Assets is free from all former grants, sales, taxes, assessments, liens, trusts, mortgages and encumbrances created by or through [Exiting Participant] through the Exit Date; and (ii) nothing contained herein shall be construed to relieve [Exiting Participant] from its duties under the Restructuring Agreement, the Decommissioning Agreement and the Mine Reclamation Agreement.

5. [Exiting Participant], by execution and delivery of this Instrument of Sale and Conveyance, and [Acquiring Participant], by its acceptance hereof, hereby waive and renounce for themselves, their successors, transferees and assigns, any and all rights, titles and interests of any kind or nature whatsoever, legal or equitable, as a tenant in common in the Conveyed Assets, to partition or equitable accounting.

6. This Instrument of Sale and Conveyance and the terms and conditions contained herein shall bind and inure to the benefit of the respective successors, assigns, trustees and representatives of [Exiting Participant] and [Acquiring Participant].

This Instrument of Sale and Conveyance shall be governed and construed in accordance with New Mexico law.

IN WITNESS WHEREOF, [Exiting Participant] has caused this Instrument of Sale and Conveyance to be executed as of the ___ day of ___, 2017.

[Exiting Participant]

By: ________________

Its: ________________

ACKNOWLEDGEMENT

STATE OF ____________ )

) ss.

COUNTY OF __________ )

This instrument was acknowledged before me on ________, 2017 by ___________________, as ___________ of ____________________, a _______________.

________________________________

Notary Public

My Commission Expires: ___________

C-2

EXECUTION VERSION

EXHIBIT D

Form of Opinion of Counsel

The legal opinions of counsel for each of the Parties required by Section 17.3 of the Restructuring Agreement will be to the following effect:

[Addressed to Parties]

Ladies and Gentlemen: [Expand as appropriate to encompass customary qualifications and limitations and other relevant language]

We have acted as counsel to ________________ [Insert name of the Party on whose behalf this opinion is provided] in connection with the San Juan Project Restructuring Agreement among Public Service Company of New Mexico; Tucson Electric Power Company; The City of Farmington, New Mexico; M-S-R Public Power Agency; The Incorporated County of Los Alamos, New Mexico; Southern California Public Power Authority; City of Anaheim; Utah Associated Municipal Power Systems; Tri-State Generation and Transmission Association, Inc.; and PNMR Development and Management Corporation, dated as of July 31, 2015 (“Restructuring Agreement”) (each a “Party” and collectively the “Parties”). Section 17 of the Restructuring Agreement contains certain representations and warranties of the Parties to one another; and Section 17.3 provides that counsel for each Party will provide its opinion to each of the other Parties that the Party is in compliance with the representations and warranties given in Section 17. This opinion of counsel is given in accordance with Section 17.3 of the Restructuring Agreement.

We are of the opinion that the representations and warranties made by _________________ [Insert name of the Party on whose behalf this opinion is provided] pursuant to Section 17 of the Restructuring Agreement are true and correct in all material respects as of the Execution Date of the Restructuring Agreement (as that date is defined in the Restructuring Agreement). No facts have come to our attention, after reasonable inquiry, which would lead us to believe that the Section 17 representations and warranties of ____________ [Insert name of the Party on whose behalf this opinion is provided] contain any untrue statement of a material fact or omit to state any material fact necessary in order to make such statements, in the light of the circumstances under which they are being made, not misleading.

The opinions expressed herein are based only on the laws of the State of __________ [Insert State] in effect as of the date of this opinion and in all respects are subject to and may be limited by future legislation, as well as developing case law. We undertake no duty to advise you of the same.

D-1

EXECUTION VERSION

This letter is furnished by us as __________ [Insert Title, e.g., – General Counsel] to _____________ [Insert name of the Party on whose behalf this opinion is provided]. No attorney-client relationship has existed or exists between us and you in connection with the transactions provided for in the Restructuring Agreement or by virtue of this letter. This letter is delivered to you and is solely for your benefit and is not to be used, circulated, quoted or otherwise referred to or relied upon for any other purpose or by any other person.

D-2

EXECUTION VERSION

EXHIBIT E

Parties’ Pre-Exit Date Ownership Interests in Project Facilities

The Parties’ pre-Exit Date Ownership Interests in the Project are the following:

A. For Units 1 and 2 and for all equipment and facilities directly related to Units 1 and 2 only, in accordance with the following percentages:


•	PNM: 50 percent


•	TEP: 50 percent


•	M-S-R: 0 percent


•	Farmington: 0 percent


•	Tri-State: 0 percent


•	LAC: 0 percent


•	SCPPA: 0 percent


•	Anaheim: 0 percent


•	UAMPS: 0 percent


•	PNMR-D: 0 percent

B. For Unit 3 and for all equipment and facilities directly related to Unit 3 only, in accordance with the following percentages:


•	PNM: 50 percent


•	TEP: 0 percent


•	M-S-R: 0 percent


•	Farmington: 0 percent


•	Tri-State: 8.2 percent


•	LAC: 0 percent


•	SCPPA: 41.8 percent


•	Anaheim: 0 percent


•	UAMPS: 0 percent


•	PNMR-D: 0 percent

C. For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:


•	PNM: 38.457 percent


•	TEP: 0 percent


•	M-S-R: 28.8 percent


•	Farmington: 8.475 percent


•	Tri-State: 0 percent


•	LAC: 7.20 percent


•	SCPPA: 0 percent


•	Anaheim: 10.04 percent

E-1

EXECUTION VERSION


•	UAMPS: 7.028 percent


•	PNMR-D: 0 percent

D. For equipment and facilities common to Units 1 and 2 only, in accordance with the following percentages:


•	PNM: 50 percent


•	TEP: 50 percent


•	M-S-R: 0 percent


•	Farmington: 0 percent


•	Tri-State: 0 percent


•	LAC: 0 percent


•	SCPPA: 0 percent


•	Anaheim: 0 percent


•	UAMPS: 0 percent


•	PNMR-D: 0 percent

E. For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:


•	PNM: 44.119 percent


•	TEP: 0 percent


•	M-S-R: 14.4 percent


•	Farmington: 4.249 percent


•	Tri-State: 4.1 percent


•	LAC: 3.612 percent


•	SCPPA: 20.9 percent


•	Anaheim: 5.07 percent


•	UAMPS: 3.55 percent


•	PNMR-D: 0 percent

F. For equipment and facilities common to all of the Units in accordance with the following percentages:


•	PNM: 46.297 percent


•	TEP: 19.8 percent


•	M-S-R: 8.7 percent


•	Farmington: 2.559 percent


•	Tri-State: 2.49 percent


•	LAC: 2.175 percent


•	SCPPA: 12.71 percent


•	Anaheim: 3.10 percent


•	UAMPS: 2.169 percent


•	PNMR-D: 0 percent

E-2

EXECUTION VERSION

EXHIBIT F

SJGS Plant Site

The SJGS Plant Site consists of Parcels A, B, D, E and F in the property descriptions below.

PARCEL A

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 16: SW 1/4

Section 20: NE 1/4, N 1/2 SE 1/4, SW 1/4SE 1/4

Section 21: NW 1/4 NW 1/4

Section 29: NE 1/4

PARCEL B

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SW 1/4, SW 1/4 SE 1/4

Section 20: E 1/2 NW 1/4, NE 1/4 SW 1/4

Section 29: NW 1/4, N 1/2 SW 1/4

Section 30: NE 1/4, E 1/2 NW 1/4, N 1/2 SE 1/4

PARCEL D

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 17: SE 1/4 SW 1/4, S1/2 SE 1/4

PARCEL E

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SE 1/4

NE 1/4 SE 1/4

E 1/2 NW 1/4 SE 1/4

S 1/2 S 1/2 SE 1/4 NE 1/4

F-1

EXECUTION VERSION

Section 20: SE 1/4 SW 1/4

SW 1/4 SW 1/4

NW 1/4 SW 1/4

S 1/2 SW 1/4 SW 1/4 NW 1/4

Containing 235 acres, more or less.

PARCEL F

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 20: SE 1/4 SE 1/4

F-2

EXECUTION VERSION

EXHIBIT G

Form of Instrument Relinquishing Easement and License

TERMINATION AND RELINQUISHMENT

_____________________, a _________________organized under the laws of the State of __________, hereby terminates and relinquishes all interests acquired as Grantee in that certain Easement and License dated ______________ and recorded at Book _______, record number ____________, page __________of Records of San Juan County, New Mexico.

Dated effective this ____ day of _______________, 2017.

_____________________________________________

[__________]

_____________________________________________

Name and title

STATE OF )

) ss

COUNTY OF )

The foregoing document was acknowledged before me this _____ day of _________________, 2017 by ____________________________, as __________________________ of ______________.

___________________________________

Notary Public

___________________________________

My Commission Expires

G-1

EXECUTION VERSION

EXHIBIT H

Form of Easement and Right of Entry

PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation, and TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (together, the “Grantors”), for valuable consideration, the receipt and sufficiency of which are hereby acknowledged, hereby grant and convey to _____________________________, a _________________ organized under the laws of the State of ____________ (“Grantee”), and to Grantee’s employees, contractors, subcontractors, representatives, agents and licensees, a non-exclusive easement and right of entry to, including rights of ingress and egress upon, over and across, the SJGS Plant Site, described in Exhibit ‘A’, attached hereto and made a part hereof (the “Premises”) and to all buildings and personal property located thereon (collectively, the “Facilities”), for the purposes set forth below.

The rights and privileges granted herein give Grantee the right to access the Premises and Facilities for the purposes of Grantee exercising its rights, protecting its interests and fulfilling its obligations under the San Juan Project Restructuring Agreement dated July 31, 2015, (“Restructuring Agreement”), the Amended and Restated Mine Reclamation and Trust Funds Agreement dated July 31, 2015 (“Mine Reclamation Agreement”), and the San Juan Decommissioning and Trust Funds Agreement dated July 31, 2015 (“Decommissioning Agreement”), to which Grantors and Grantee are parties (collectively, the “Purposes”).

Grantors will make and keep available to Grantee all reasonable accommodations appropriate for Grantee’s full use and enjoyment of this Easement and Right of Entry for carrying out the Purposes, including, without limitation, parking and security clearances appropriate for passage to and from the Premises and the Facilities, all upon reasonable advance notice and consistent with the San Juan Project Operating Agent’s safety and security rules and other requirements applicable to persons who come upon the Premises and the Facilities.

This Easement and Right of Entry shall automatically expire, without any further or additional document or act, upon the last to occur of the following: (i) the termination or expiration of the Restructuring Agreement; (ii) the termination or expiration of the Mine Reclamation Agreement; and (iii) the termination or expiration of the Decommissioning Agreement. Further, this instrument is not assignable or transferable in whole or in part by Grantee without the prior written approval of such assignment by Grantors which approval will not be unreasonably conditioned, delayed or denied. Upon the last to occur of items (i), (ii) or (iii), above, Grantors may, upon thirty (30) days’ written notice to Grantee, execute and record in the real estate records of San Juan County, New Mexico, a written instrument certifying that this Easement and Right of Entry has terminated.

Dated effective this ____ day of _______________, 2017.

H-1

EXECUTION VERSION

Public Service Company of New Mexico

By:_____________________________________________

Name:___________________________________________

Title:____________________________________________

Tucson Electric Power Company

By:_____________________________________________

Name:___________________________________________

Title:____________________________________________

STATE OF NEW MEXICO )

) ss

COUNTY OF )

The foregoing document was acknowledged before me this _____ day of _________________, 2017 by ____________________________, as __________________________ of Public Service Company of New Mexico.

___________________________________

Notary Public

__________________________________

My Commission Expires:

STATE OF ARIZONA )

) ss

COUNTY OF PIMA )

The foregoing document was acknowledged before me this _____ day of _________________, 2017 by ____________________________, as __________________________ of Tucson Electric Power Company.

___________________________________

Notary Public

____________________________________

My Commission Expires:

H-2

EXECUTION VERSION

EXHIBIT A

TO EASEMENT AND RIGHT OF ENTRY

DESCRIPTION OF SJGS PLANT SITE

PARCEL A

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 16: SW 1/4

Section 20: NE 1/4, N 1/2 SE 1/4, SW 1/4SE 1/4

Section 21: NW 1/4 NW 1/4

Section 29: NE 1/4

PARCEL B

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SW 1/4, SW 1/4 SE 1/4

Section 20: E 1/2 NW 1/4, NE 1/4 SW 1/4

Section 29: NW 1/4, N 1/2 SW 1/4

Section 30: NE 1/4, E 1/2 NW 1/4, N 1/2 SE 1/4

PARCEL D

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 17: SE 1/4 SW 1/4, S1/2 SE 1/4

PARCEL E

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SE 1/4

NE 1/4 SE 1/4

E 1/2 NW 1/4 SE 1/4

S 1/2 S 1/2 SE 1/4 NE 1/4

H-3

EXECUTION VERSION

Section 20: SE 1/4 SW 1/4

SW 1/4 SW 1/4

NW 1/4 SW 1/4

S 1/2 SW 1/4 SW 1/4 NW 1/4

Containing 235 acres, more or less.

PARCEL F

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 20: SE 1/4 SE 1/4

H-4

EXECUTION VERSION

EXHIBIT I

Form of Parental Guaranty

PARENTAL GUARANTY AGREEMENT

Reference is hereby made to the following agreements: (1) SAN JUAN PROJECT RESTRUCTURING AGREEMENT (“Restructuring Agreement”), executed as of ___________, 2015 by and among PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“PNM”); TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“TEP”); THE CITY OF FARMINGTON, NEW MEXICO, an incorporated municipality and a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Farmington”); M-S-R PUBLIC POWER AGENCY, a joint exercise of powers agency organized under the laws of the State of California (“M-S-R”); THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO, a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Los Alamos”); SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, a joint exercise of powers agency organized under the laws of the State of California (“SCPPA”); CITY OF ANAHEIM, a municipal corporation organized under the laws of the State of California (“Anaheim”); UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS, a political subdivision of the State of Utah (“UAMPS”); TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC., a Colorado cooperative corporation (“Tri-State”); and PNMR DEVELOPMENT AND MANAGEMENT CORPORATION, a New Mexico corporation (“PNMR-D”); (2) SAN JUAN DECOMMISSIONING AND TRUST FUNDS AGREEMENT (“Decommissioning Agreement”), dated as of ________, 2015, by and among PNM; TEP; Farmington; M-S-R; LAC; SCPPA; Anaheim; UAMPS; Tri-State; and PNMR-D; (3) AMENDED AND RESTATED MINE RECLAMATION AND TRUST FUNDS AGREEMENT (“Mine Reclamation Agreement”), executed as of ____________, 2015, by and among PNM; TEP; Farmington; M-S-R; LAC; SCPPA; Anaheim; UAMPS; Tri-State; and PNMR-D; and (4) AMENDED AND RESTATED SAN JUAN PROJECT PARTICIPATION AGREEMENT (“SJPPA”) dated as of March 23, 2006, as amended, by and among PNM; TEP; Farmington; M-S-R; LAC; SCPPA; Anaheim; UAMPS; Tri-State; and PNMR-D. The Restructuring Agreement, Decommissioning Agreement, Mine Reclamation Agreement and SJPPA are hereinafter collectively referred to as “Guaranteed Agreements,” and TEP, M-S-R, LAC, PNM, Farmington, Anaheim, UAMPS, SCPPA and Tri-State are hereinafter collectively referred to as “Guaranteed Parties.”

FOR VALUE RECEIVED, and in consideration of any loans, advances, payments, extensions of credit and/or other financial accommodations heretofore, now or hereafter made, granted or extended by the Guaranteed Parties, and their respective successors and assigns, or which the Guaranteed Parties and/or their respective successors and assigns have or will become obligated to make, grant or extend, to or for the account of PNMR-D, and in consideration of any obligations heretofore, now or hereafter incurred by PNMR-D to the Guaranteed Parties and/or their respective successors and assigns, Guarantor hereby absolutely and unconditionally guarantees to each of the Guaranteed Parties and their respective successors and assigns the prompt and complete payment and performance when due in accordance with their terms (whether by reason of demand, maturity, acceleration or otherwise) of any and all present and

I-1

EXECUTION VERSION

future obligations of PNMR-D to any one or more of the Guaranteed Parties, including, without limitation, all obligations of PNMR-D to the Guaranteed Parties under the Guaranteed Agreements (herein referred to as the “Guaranteed Obligations”). In addition, Guarantor shall and agrees to be liable to the Guaranteed Parties for all costs and expenses incurred by the Guaranteed Parties in attempting or effecting collection under this Parental Guaranty Agreement (whether or not litigation shall be commenced in aid thereof) and in connection with representation of the Guaranteed Parties in connection with bankruptcy or insolvency proceedings relating to or affecting this Parental Guaranty Agreement, including, without limitation, reasonable Attorneys’ Fees for outside counsel for Guaranteed Parties, and interest payable on the Guaranteed Obligations as provided for in the Guaranteed Agreements or under applicable law. Guarantor agrees, represents and warrants that its obligations under this Parental Guaranty Agreement are, and will remain until all of its obligations hereunder have been fully and unconditionally performed and satisfied, ranked on parity with other unsecured and unsubordinated obligations of Guarantor to any other person or entity. Except as may be otherwise provided herein, in no event will Guarantor be liable under any provision of this Parental Guaranty Agreement for any indirect, special, punitive or incidental damages or costs of the Guaranteed Parties (including loss of revenue, cost of capital and loss of business reputation or opportunity), whether based in contract, tort (including, without limitation, negligence or strict liability), or otherwise, and the Guaranteed Parties hereby waive, release and discharge Guarantor from all such indirect, special, punitive and incidental damages and costs.

Notice of the acceptance of this Parental Guaranty Agreement, and of the incurrence of any of the Guaranteed Obligations, and presentment, demand for payment, notice of dishonor, protest, notice of protest and of default by PNMR-D are hereby waived by Guarantor. Guarantor hereby agrees that (a) this Parental Guaranty Agreement is a guaranty of payment and not of collection, and the obligations of such Guarantor under this Parental Guaranty Agreement may be enforced directly against such Guarantor independently of and without proceeding against PNMR-D with respect to any or all of the Guaranteed Obligations or foreclosing any collateral pledged to the Guaranteed Parties, and (b) the Guaranteed Parties may from time to time, in their sole and absolute discretion and without notice to or consent of such Guarantor and without releasing such Guarantor from any of its obligations under this Parental Guaranty Agreement, (i) extend the time of payment, change the interest rates and renew or change the manner, place, time and/or terms of payment of and make any other changes with respect to any or all of the Guaranteed Obligations, (ii) sell, exchange, release, surrender and otherwise deal with any collateral pledged to the Guaranteed Parties by PNMR-D or any other person to secure any or all of the Guaranteed Obligations, (iii) release and otherwise deal with any other guarantor(s) of any or all of the Guaranteed Obligations, (iv) exercise or refrain from exercising any rights against PNMR-D of any or all of the Guaranteed Obligations and otherwise act or refrain from acting with respect to PNMR-D of any or all of the Guaranteed Obligations and/or (v) settle or compromise any or all of the Guaranteed Obligations with PNMR-D.

Guarantor will not have any right of subrogation, reimbursement, contribution or indemnity whatsoever with respect to PNMR-D of any or all of the Guaranteed Obligations or any right of recourse to or with respect to any assets or property of PNMR-D of any or all of the Guaranteed Obligations or to any collateral or other security for the payment of any or all of the Guaranteed Obligations unless and until (a) all of the Guaranteed Obligations have been fully, finally and indefeasibly paid in cash (except with respect to contingent indemnification

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obligations), (b) none of the Guaranteed Parties has any further commitment or obligation to advance funds, make loans, extend credit to or for the account of PNMR-D under the Guaranteed Agreements and/or enter into any Guaranteed Obligations and (c) this Parental Guaranty Agreement has been terminated. Nothing will discharge or satisfy the liability of Guarantor under this Parental Guaranty Agreement except the full performance and payment of all of the Guaranteed Obligations and all obligations of such Guarantor under this Parental Guaranty Agreement.

The books and records of the Guaranteed Parties showing the account between the Guaranteed Parties and PNMR-D shall be admissible in evidence in any action or proceeding and shall constitute prima facie proof of the items therein set forth.

No invalidity, irregularity or unenforceability of any or all of the Guaranteed Obligations or of any collateral or any other guarantees therefor shall affect, impair or be a defense to this Parental Guaranty Agreement. The liability of the Guarantor under this Parental Guaranty Agreement will in no way be affected or impaired by any acceptance by the Guaranteed Parties of any collateral for or other guarantees of any of the Guaranteed Obligations, or by any failure, neglect or omission on the part of the Guaranteed Parties to realize upon or protect any of the Guaranteed Obligations or any collateral therefor or guarantees thereof. No act of commission or omission of any kind by the Guaranteed Parties (including, without limitation, any act or omission which impairs, reduces the value of, releases or fails to perfect a security interest in and/or a lien on, any collateral for or guarantee of any of the Guaranteed Obligations) shall affect or impair the obligations of Guarantor under this Parental Guaranty Agreement in any manner.

Guarantor hereby waives any right to require the Guaranteed Parties to (a) proceed against PNMR-D, (b) marshal assets or proceed against or exhaust any security held from PNMR-D, (c) give notice of the terms, time and place of any public or private sale or other disposition of personal property security held from PNMR-D, (d) take any action or pursue any other remedy in the Guaranteed Parties’ power and/or (e) make any presentment or demand for performance, or give any notice of nonperformance, protest, notice of protest or notice of dishonor under this Parental Guaranty Agreement or in connection with any obligations or evidences of obligations held by the Guaranteed Parties as security for or which constitute in whole or in part the Guaranteed Obligations, or in connection with the creation of new or additional Guaranteed Obligations.

Guarantor hereby waives any defense to its obligations under this Parental Guaranty Agreement based upon or arising by reason of (a) any disability or other defense of PNMR-D or any other person or entity, (b) the cessation or limitation from any cause whatsoever, other than indefeasible payment in full, of the Guaranteed Obligations, (c) any lack of authority of any officer, director, partner, agent or any other person or entity acting or purporting to act on behalf of PNMR-D, or any defect in the formation of PNMR-D, (d) the application by PNMR-D of the proceeds of any of the Guaranteed Obligations for purposes other than the purposes represented by PNMR-D to, or intended or understood by, the Guaranteed Parties and/or the Guarantor, (e) any act or omission by the Guaranteed Parties which directly or indirectly results in or aids the discharge of PNMR-D or all or any portion of the Guaranteed Obligations by operation of law or otherwise, or which in any way impairs or suspends any rights or remedies of the Guaranteed Parties against PNMR-D, (f) any impairment of the value of any interest in any security for the

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Guaranteed Obligations or any portion thereof, including without limitation, the failure to obtain or maintain perfection or recordation of any interest in any such security, the release of any such security without substitution and/or the failure to preserve the value of, or to comply with applicable law in disposing of, any such security, (g) any modification of any or all of the Guaranteed Obligations, in any form whatsoever, including, without limitation, the renewal, extension, acceleration or other change in time for payment of, or other change in the terms of, the Guaranteed Obligations or any portion thereof, including increasing or decreasing the rate of interest thereon and/or (h) any requirement that the Guaranteed Parties give any notice of acceptance of this Guaranty. Guarantor hereby further waives all rights and defenses which such Guarantor may have arising out of (a) any election of remedies by the Guaranteed Parties, even though that election of remedies, such as a non-judicial foreclosure with respect to any security for any portion of the Guaranteed Obligations, impairs, diminishes, negates or destroys such Guarantor’s rights of subrogation or such Guarantor’s rights to proceed against PNMR-D for reimbursement or (b) any loss of rights such Guarantor may suffer by reason of any rights, powers or remedies of PNMR-D in connection with any anti-deficiency laws or any other laws limiting, qualifying or discharging the Guaranteed Obligations, whether by operation of law or otherwise, including any rights which such Guarantor may have to a fair market value hearing to determine the size of a deficiency following any foreclosure sale or other disposition of any real property security for any portion of the Guaranteed Obligations. Guarantor acknowledges and agrees that the waivers in the immediately preceding sentence constitute unconditional and irrevocable waivers of any rights and defenses Guarantor may have, and that such rights and defenses include, without limitation, any rights and defenses based upon any and all applicable state statutes.

GUARANTOR HEREBY FURTHER WAIVES ANY AND ALL OTHER SURETYSHIP DEFENSES.

Guarantor hereby represents and warrants to the Guaranteed Parties that (a) such Guarantor is a New Mexico company duly formed, validly existing and in good standing under the laws of the State of New Mexico, (b) the execution, delivery and performance by such Guarantor of this Parental Guaranty Agreement (i) are within company powers of such Guarantor, (ii) have been duly authorized by all necessary company action on the part of such Guarantor, (iii) require no action by or in respect of, consent or approval of or filing or recording with, any governmental or regulatory body, instrumentality, authority, agency or official or any other person or entity and (iv) do not conflict with, or result in a breach of the terms, conditions or provisions of, or constitute a default under or result in any violation of, the terms of the Articles of Incorporation, Bylaws and any other governing document of Guarantor, any applicable law, rule, regulation, order, writ, judgment or decree of any court or governmental or regulatory body, instrumentality, authority, agency or official or any agreement, document or instrument to which such Guarantor is a party or by which such Guarantor or any of its property or assets is bound or to which Guarantor or any of its property or assets is subject and (c) this Parental Guaranty Agreement constitutes the legal, valid and binding obligation of Guarantor and is enforceable against Guarantor in accordance with its terms, except as such enforceability may be limited by (i) applicable bankruptcy, insolvency or similar laws affecting the enforcement of creditors’ rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

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No delay by the Guaranteed Parties in exercising any of their options, powers or rights under this Parental Guaranty Agreement and/or any partial or single exercise thereof shall constitute a waiver thereof. No waiver of any of the rights and/or remedies of the Guaranteed Parties under this Parental Guaranty Agreement and no modification or amendment of this Parental Guaranty Agreement shall be deemed to be made by the Guaranteed Parties unless the same shall be in writing, duly signed on behalf of the Guaranteed Parties and each such waiver (if any) shall apply only with respect to the specific instance involved and shall in no way impair the rights of the Guaranteed Parties or the obligations of the Guarantor to the Guaranteed Parties in any other respect at any other time. In the event any one or more of the provisions contained in this Parental Guaranty Agreement should be invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions of this Parental Guaranty Agreement shall not be affected or impaired thereby.

All payments made under or pursuant to this Parental Guaranty Agreement shall be paid for the benefit of the Guaranteed Parties and shall be allocated among the principal, interest and other portions of the Guaranteed Obligations and the other obligations of the Guarantor under this Parental Guaranty Agreement in the order and manner set forth in the Guaranteed Agreements.

Guarantor hereby covenants and agrees to deliver to the Guaranteed Parties (a) such publicly-available financial statements and other publicly-available financial information regarding the Guarantor as reasonably requested by the Guaranteed Parties . , and (b) notice and a true and correct executed copy of any other guaranty executed by Guarantor to guarantee any obligations of PNMR-D entered into at any time after the date this Parental Guaranty Agreement is executed and before the date of termination hereof.

This Parental Guaranty Agreement is a continuing guaranty which will remain in full force and effect and will not be terminable unless and until (a) all of the Guaranteed Obligations have been fully and finally paid in cash (except with respect to contingent indemnification obligations), (b) none of the Guaranteed Parties has any further commitment or obligation to advance funds, make loans, extend credit to or for the account of PNMR-D under the Guaranteed Agreements, and/or enter into any Guaranteed Obligations and (c) the Guaranteed Agreements have expired or been terminated in accordance with their terms. The dissolution of the Guarantor shall not effect a termination of this Parental Guaranty Agreement. If claim is ever made on the Guaranteed Parties for repayment or recovery of any amount or amounts received by the Guaranteed Parties in payment or on account of any of the Guaranteed Obligations (including payment under a guaranty or from application of collateral) and the Guaranteed Parties repay or disgorge all or part of said amount by reason of (a) any judgment, decree or order of any court or administrative body having jurisdiction over the Guaranteed Parties or any of the property or assets of the Guaranteed Parties or (b) any settlement or compromise of any such claim effected by the Guaranteed Parties with any such claimant (including, without limitation, PNMR-D and/or Guarantor), then and in such event Guarantor agrees that any such judgment, decree, order, settlement or compromise shall be binding on such Guarantor, notwithstanding any cancellation of any note or other instrument or agreement evidencing such Guaranteed Obligations or of this Parental Guaranty Agreement, and Guarantor will be and remain liable to the Guaranteed Parties under this Parental Guaranty Agreement for the amount so repaid, recovered or disgorged to the same extent as if such amount had never originally been received

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by the Guaranteed Parties. This Parental Guaranty Agreement will continue to be effective or be reinstated, as the case may be, if (a) at any time any payment of any of the Guaranteed Obligations is rescinded, cancelled, voided or must otherwise be returned by or is disgorged from the Guaranteed Parties for any reason including, without limitation, the insolvency, bankruptcy or reorganization of PNMR-D, Guarantor or otherwise, all as though such payment had not been made or (b) this Parental Guaranty Agreement is released or the liability of Guarantor under this Parental Guaranty Agreement is reduced in consideration of a payment of money or transfer of property or grant of a security interest by PNMR-D, Guarantor or any other person and such payment, transfer or grant is rescinded, cancelled, voided or must otherwise be returned by or disgorged from the Guaranteed Parties for any reason including, without limitation, the insolvency, bankruptcy or reorganization of such person or otherwise, all as though such payment, transfer or grant had not been made.

Any notice, demand or other communication to Guarantor under this Parental Guaranty Agreement will be in writing and delivered in person or sent by facsimile, recognized overnight courier or registered or certified mail (return receipt requested) to Guarantor at the address or facsimile number for the Guarantor set forth on the signature page(s) of this Parental Guaranty Agreement, or at such other address or facsimile number as the Guarantor may designate as its address or facsimile number for communications under this Parental Guaranty Agreement. Such notices will be deemed effective on the day on which delivered or sent if delivered in person or sent by facsimile, on the first (1st) business day after the day on which sent, if sent by recognized overnight courier or on the third (3rd) business day after the day on which sent, if sent by registered or certified mail.

This Parental Guaranty Agreement will be understood to be for the benefit of the Guaranteed Parties, individually and collectively, and for such other person or persons as may from time to time become or be the holder or owner of any of the Guaranteed Obligations or any interest therein and this Parental Guaranty Agreement will be transferable to the same extent and with the same force and effect as any of the Guaranteed Obligations may be transferable, and any one or more of the Guaranteed Parties may, but is not required to, demand payment or performance hereunder by the Guarantor. This Parental Guaranty Agreement cannot be changed or terminated orally, will be governed by and construed in accordance with the substantive laws of the State of New Mexico (without reference to conflict of law principles), will be binding on the successors and permitted assigns of Guarantor and will inure to the benefit of the respective successors and assigns of the Guaranteed Parties. Guarantor may not assign or delegate any of its rights, obligations or duties under this Parental Guaranty Agreement without the prior written consent of the Guaranteed Parties.

GUARANTOR HEREBY IRREVOCABLY (A) SUBMITS TO THE NON-EXCLUSIVE JURISDICTION OF ANY NEW MEXICO STATE COURT OR FEDERAL COURT IN ALBUQUERQUE, NEW MEXICO, AS THE GUARANTEED PARTIES MAY ELECT, IN ANY SUIT, ACTION OR PROCEEDING ARISING OUT OF OR RELATING TO THIS PARENTAL GUARANTY AGREEMENT, (B) AGREES THAT ALL CLAIMS IN RESPECT TO ANY SUCH SUIT, ACTION OR PROCEEDING MAY BE HELD AND DETERMINED IN ANY OF SUCH COURTS, (C) WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH GUARANTOR MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH SUIT, ACTION OR

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PROCEEDING BROUGHT IN ANY SUCH COURT, (D) WAIVES ANY CLAIM THAT SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM AND (E) WAIVES ALL RIGHTS OF ANY OTHER JURISDICTION WHICH GUARANTOR MAY NOW OR HEREAFTER HAVE BY REASON OF ITS PRESENT OR SUBSEQUENT DOMICILES. GUARANTOR (AND BY THEIR ACCEPTANCE HEREOF) THE GUARANTEED PARTIES HEREBY IRREVOCABLY WAIVE THE RIGHT TO TRIAL BY JURY WITH RESPECT TO ANY ACTION IN WHICH GUARANTOR, ON THE ONE HAND, AND THE GUARANTEED PARTIES, ON THE OTHER HAND, ARE PARTIES RELATING TO OR ARISING OUT OF OR IN CONNECTION WITH THIS PARENTAL GUARANTY AGREEMENT.

Executed as of the ____ day of_______.

PNM RESOURCES, INC., a New Mexico corporation

Guarantor

By__________________________________________

Title: _______________________________________

Contact information of Guarantor, Guaranteed Parties and PNMR-D for purpose of Notices:

PNM Resources, Inc.

414 Silver Avenue SW

Albuquerque, NM 87102

Attention: Secretary

FAX No. (505) 241-2368

PNMR Development and Management Corporation

414 Silver Avenue SW

Albuquerque, NM 87102

Attention: Secretary

FAX No. (505) 241-2368

Public Service Company of New Mexico

Attn: Vice President, PNM Generation

2401 Aztec N.E., Bldg. A

Albuquerque, NM 87107

With a copy to:

Public Service Company of New Mexico

c/o Secretary

414 Silver Ave. S.W.

Albuquerque, NM 87102

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Tucson Electric Power Company

88 E. Broadway Blvd.

MS HQE901

Tucson, AZ 85701

Attn: Corporate Secretary

City of Farmington

c/o City Clerk

800 Municipal Drive

Farmington, NM 87401

With a copy to:

Farmington Electric Utility System

Electric Utility Director

101 North Browning Parkway

Farmington, NM 87401

Incorporated County of Los Alamos, New Mexico

c/o County Clerk

P.O. Drawer 1030

170 Central Park Square

Suite 240

Los Alamos, NM 87544

with a copy to:

Incorporated County of Los Alamos, New Mexico

c/o Utilities Manager

P.O. Drawer 1030

170 Central Park Square

Suite 240

Los Alamos, NM 87544

Utah Associated Municipal Power Systems

c/o General Manager

155 North 400 West

Suite 480

Salt Lake City, UT 84103

City of Anaheim

Attention: City Clerk

200 South Anaheim Boulevard

Anaheim, CA 92805

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with a copy to:

City of Anaheim

Attention: Public Utilities General Manager

201 South Anaheim Blvd., Suite 1101

Anaheim, CA 92805

FAX No. (714) 765-4138

M-S-R Public Power Agency

Attention: General Manager

1231 11th Street

Modesto, CA 95354

FAX No. (209) 526-7574

Southern California Public Power Authority

c/o Executive Director

1160 Nicole Court

Glendora, CA 91740

Tri-State Generation and Transmission Association, Inc.

c/o Chief Executive Officer

1100 West 116 ^th Avenue

Westminster, CO 80234

Or P. O. Box 33695

Denver, CO 80233

For purposes of overnight courier service, Tri-State’s address will be:

Tri-State Generation and Transmission Association, Inc.

c/o Chief Executive Officer

3761 Eureka Way

Frederick, CO 80516

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EXHIBIT J

FORM OF LETTER OF CREDIT

L/C NUMBER AMOUNT EXPIRATION DATE

BENEFICIARY NAME APPLICANT NAME

BENEFICIARY ADDRESS APPLICANT ADDRESS

WE HEREBY OPEN OUR IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT IN YOUR FAVOR IN CONNECTION WITH _________________ AGREEMENT DATED AS OF__________________ FOR THE ACCOUNT OF THE ABOVE REFERENCED APPLICANT IN THE AGGREGATE AMOUNT OF (Ten Million Dollars) WHICH IS AVAILABLE BY PAYMENT WHEN ACCOMPANIED BY THE FOLLOWING DOCUMENTS:

1. A DRAFT AT SIGHT DRAWN ON ____________________________________, DULY ENDORSED ON ITS REVERSE SIDE THEREOF BY THE BENEFICIARY, SPECIFICALLY REFERENCING THIS LETTER OF CREDIT NUMBER.

2. THE ORIGINAL LETTER OF CREDIT AND ANY AMENDMENTS ATTACHED THERETO.

3. COPY OF INVOICE MARKED UNPAID IN THE CASE OF ITEM 4.A, AND

4. A STATEMENT ISSUED ON THE LETTERHEAD OF AND PURPORTEDLY SIGNED BY AN AUTHORIZED REPRESENTATIVE OF THE BENEFICIARY STATING THE FOLLOWING:


A.	THE APPLICANT HAS NOT MADE PAYMENT ON INVOICE NUMBER (INSERT INVOICE NUMBER) PER OUR AGREED TERMS. WE THEREFORE DEMAND PAYMENT IN THE AMOUNT OF (INSERT AMOUNT) AS SAME IS DUE AND OWING; or


B.	AT THE TIME OF ISSUANCE OF LETTER OF CREDIT NO. [INSERT NUMBER], [NAME OF ISSUING BANK] HAD A LONG TERM OBLIGATION RATING FROM ONE OR MORE OF THE FOLLOWING CREDIT RATING AGENCIES OF AT LEAST: MOODY’S, A3 OR BETTER; STANDARD & POOR’S, A- OR BETTER; AND/OR FITCH, A- OR BETTER. SAID RATING(S) HAS/HAVE FALLEN BELOW THAT EXISTING AT THE TIME OF ISSUANCE OF THE LETTER OF CREDIT.

INVOICE(S) IN EXCESS OF AMOUNT AVAILABLE UNDER THIS LETTER OF CREDIT ARE ACCEPTABLE, HOWEVER, DRAWINGS UNDER THIS LETTER OF CREDIT MAY NOT EXCEED AMOUNT AVAILABLE.

PARTIAL DRAWINGS UNDER THIS LETTER OF CREDIT ARE PERMITTED.

MULTIPLE DRAWINGS UNDER THIS LETTER OF CREDIT ARE PERMITTED.

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ALL BANKING CHARGES OF THE ISSUER ASSOCIATED WITH THIS LETTER OF CREDIT ARE FOR THE ACCOUNT OF THE APPLICANT.

THIS LETTER OF CREDIT WILL BE AUTOMATICALLY EXTENDED EACH YEAR WITHOUT AMENDMENT FOR A PERIOD OF AT LEAST ONE YEAR FROM THE EXPIRATION DATE HEREOF, AS EXTENDED, UNLESS AT LEAST FORTY-FIVE (45) DAYS PRIOR TO THE EXPIRATION DATE, WE NOTIFY THE BENEFICIARY AND APPLICANT BY A NATIONALLY RECOGNIZED OVERNIGHT COURIER OR CERTIFIED MAIL THAT WE ELECT NOT TO EXTEND THIS LETTER OF CREDIT FOR SUCH ADDITIONAL PERIOD (THE PRESENT OR ANY FUTURE EXPIRATION DATE AS AFORESAID IS REFERRED TO HEREIN AS THE “EXPIRATION DATE”). WE WILL GIVE NOTICE OF NON-EXTENSION TO THE BENEFICIARY AT THE BENEFICIARY'S ADDRESS SET FORTH HEREIN OR AT SUCH OTHER ADDRESS AS THE BENEFICIARY MAY DESIGNATE TO US IN WRITING AT OUR LETTERHEAD ADDRESS. FOLLOWING RECEIPT BY THE BENEFICIARY OF SUCH NOTICE, AND NO EARLIER THAN TWENTY (20) DAYS BEFORE THE EXPIRATION DATE, THE BENEFICIARY MAY DRAW THE FULL AMOUNT HEREUNDER.

IF OUR CREDIT RATING(S) FALL BELOW OUR LONG TERM OBLIGATION RATING EXISTING AT THE TIME OF ISSUANCE OF THE LETTER OF CREDIT, WE WILL GIVE NOTICE OF SUCH EVENT TO THE BENEFICIARY AND APPLICANT BY A NATIONALLY RECOGNIZED OVERNIGHT COURIER OR CERTIFIED MAIL. WE WILL GIVE SUCH NOTICE TO THE BENEFICIARY AT THE BENEFICIARY'S ADDRESS SET FORTH HEREIN OR AT SUCH OTHER ADDRESS AS THE BENEFICIARY MAY DESIGNATE TO US IN WRITING AT OUR LETTERHEAD ADDRESS. FOLLOWING RECEIPT BY THE BENEFICIARY OF SUCH NOTICE, AND NO EARLIER THAN TWENTY-FIVE (25) DAYS AFTER RECEIPT OF SUCH NOTICE, THE BENEFICIARY MAY DRAW THE FULL AMOUNT HEREUNDER.

THIS IRREVOCABLE LETTER OF CREDIT SETS FORTH IN FULL THE TERMS OF OUR UNDERTAKING. THIS UNDERTAKING SHALL NOT IN ANY WAY BE MODIFIED, AMENDED, AMPLIFIED OR INCORPORATED BY REFERENCE TO ANY DOCUMENT, CONTRACT, AGREEMENT REFERENCED TO HEREIN.

WE HEREBY AGREE WITH YOU THAT DRAFT(S) DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS AND CONDITIONS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED IF PRESENTED TOGETHERWITH DOCUMENT(S) AS SPECIFIED AT OUR OFFICE LOCATED AT ____________________________ ATTENTION: STANDBY LETTERS OF CREDIT ON OR BEFORE _________________________________

THE ABOVE STATED EXPIRY DATE, OR ANY EXTENDED EXPIRY DATE IF APPLICABLE. DRAFT(S) DRAWN UNDER THIS LETTER OF CREDIT MUST SPECIFICALLY REFERENCE OUR LETTER OF CREDIT NUMBER.

EXCEPT AS OTHERWISE EXPRESSLY STATED HEREIN, THIS LETTER OF CREDIT IS SUBJECT TO THE INTERNATIONAL STANDBY PRACTICES 1998, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 590 ("ISP98").

SINCERELY,

AUTHORIZED SIGNATURE

XXX

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PLEASE DIRECT ANY CORRESPONDENCE INCLUDING DRAWING OR INQUIRY QUOTING OUR LETTER OF CREDIT NUMBER TO:

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EXHIBIT K

Form of Bring-Down Opinion of Counsel

The legal opinions of counsel for each of the Exiting Participants and Acquiring Participants required by Sections 7.3.4 and 7.4.3 of the Restructuring Agreement will be to the following effect:

[Addressed to Exiting and Acquiring Participants]

Ladies and Gentlemen: [Expand as appropriate to encompass customary qualifications and limitations and other relevant language]

We have acted as counsel to ______________ [Insert name of Party on whose behalf this opinion is provided] in connection with the San Juan Project Restructuring Agreement among Public Service Company of New Mexico; Tucson Electric Power Company; The City of Farmington, New Mexico; M-S-R Public Power Agency; The Incorporated County of Los Alamos, New Mexico; Southern California Public Power Authority; City of Anaheim; Utah Associated Municipal Power Systems; Tri-State Generation and Transmission Association, Inc.; and PNMR Development and Management Corporation, dated as of July 31, 2015 (“Restructuring Agreement”) (each a “Party” and collectively the “Parties”). We have been advised that in accordance with Section 7 of the Restructuring Agreement all of the transactions contemplated to take place at the Closing are ready to close and all of the conditions precedent to the Closing have been satisfied or waived. Section [7.3.4 or 7.4.2] of the Restructuring Agreement provides for the giving of this bring-down opinion.

Pursuant to Section 17.3 of the Restructuring Agreement, we rendered to the other Parties a legal opinion, dated __________, 2015 [Date of Prior Opinion] (“Prior Opinion”), with respect to __________________ [Insert name of the Party on whose behalf this opinion is provided]. In connection with the Closing, as defined in Section 7 of the Restructuring Agreement, we hereby reaffirm the Prior Opinion, as though it was dated the date hereof, in the form it was so rendered on __________, 2015 [Date of Prior Opinion].

In addition to the foregoing, we are of the opinion that the representations and warranties made by ________________ [Insert name of the Party on whose behalf this opinion is provided] pursuant to Section 17.3 of the Restructuring Agreement were true and correct in all material respects as of the date of the Prior Opinion and are true and correct in all material respects as of the date hereof, and no facts have come to our attention, after reasonable inquiry, which would lead us to believe that such representations and warranties contained or contain any untrue statement of a material fact or omitted to state or omit to state any material fact necessary in order to make such statements, in the light of the circumstances under which they were made, not misleading.

The opinions expressed herein are based only on the laws of the State of _____________ [Insert State] in effect as of the date of this opinion and in all respects are subject to and may be

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limited by future legislation, as well as developing case law. We undertake no duty to advise you of the same.

This letter is furnished by us as ____________

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RESTRUCTURING AMENDMENT AMENDING AND RESTATING THE

AMENDED AND RESTATED

SAN JUAN PROJECT PARTICIPATION AGREEMENT

AMONG

PUBLIC SERVICE COMPANY OF NEW MEXICO

TUCSON ELECTRIC POWER COMPANY

THE CITY OF FARMINGTON, NEW MEXICO

M-S-R PUBLIC POWER AGENCY

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY

CITY OF ANAHEIM

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

July 31, 2015

EXECUTION VERSION

TABLE OF CONTENTS



SECTION	I. PARTIES AND INTRODUCTORY MATTERS	PAGE
1	PARTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	1
2	RECITALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	3
3	AGREEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	10
4	EFFECTIVE DATE AND TERMINATION . . . . . . . . . . . . . . . . . . . . . . . .	11
5	DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	13
	II. OWNERSHIP OF SAN JUAN PROJECT
6	OWNERSHIPS AND TITLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	28
7	CAPITAL IMPROVEMENTS AND RETIREMENTS OF SAN JUAN PROJECT AND PARTICIPANTS’ SOLELY OWNED FACILITIES . . .	33
8	WAIVER OF RIGHT TO PARTITION . . . . . . . . . . . . . . . . . . . . . . . . . . . .	42
9	BINDING COVENANTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	43
10	MORTGAGE AND TRANSFER OF PARTICIPANTS’ INTERESTS . . .	46
11	RIGHTS OF FIRST REFUSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	49
12	RIGHTS OF PNM AND TEP IN WATER AND COAL . . . . . . . . . . . . . .	55
13	SEVERANCE OF IMPROVEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . .	56
	III. ENTITLEMENTS TO OUTPUT OF SAN JUAN PROJECT
14	ENTITLEMENT TO CAPACITY AND ENERGY . . . . . . . . . . . . . . . . . .	57
15	CAPACITY ALLOCATION OF SWITCHYARD FACILITIES . . . . . . .	59
16	USE OF FACILITIES DURING CURTAILMENTS . . . . . . . . . . . . . . . . .	61

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17	START-UP AND AUXILIARY POWER AND ENERGY REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	63
	IV. ADMINISTRATION
18	COORDINATION COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	64
19	ENGINEERING AND OPERATING COMMITTEE . . . . . . . . . . . . . . . .	69
20	FUELS COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	74
21	AUDITING COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	81
	V. BUDGETS AND OPERATING EXPENSES
22	OPERATION AND MAINTENANCE EXPENSES . . . . . . . . . . . . . . . . .	85
23	FUEL COSTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	94
24	ANNUAL BUDGETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	113
25	PAYMENT OF TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	114
26	MATERIALS AND SUPPLIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	115
27	EMERGENCY SPARE PARTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	117
	VI. OPERATING AGENT
28	OPERATION AND MAINTENANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . .	118
29	OPERATING EMERGENCY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	125
30	PAYMENT OF EXPENSES BY PARTICIPANTS . . . . . . . . . . . . . . . . . .	128
31	OPERATING INSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	131
32	SURPLUS OR RETIRED PROPERTY . . . . . . . . . . . . . . . . . . . . . . . . . . . .	136
33	REMOVAL OF OPERATING AGENT . . . . . . . . . . . . . . . . . . . . . . . . . . .	137
34	DEFAULTS BY OPERATING AGENT . . . . . . . . . . . . . . . . . . . . . . . . . . .	139

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	VII. DEFAULTS, LIABILITY AND ARBITRATION
35	DEFAULTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . .	141
36	LIABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	148
37	ARBITRATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	154
	VIII. RETIREMENT AND RECONSTRUCTION
38	DESTRUCTION, DAMAGE OR CONDEMNATION OF A UNIT. . . . .	158
39	RIGHTS OF PARTICIPANTS UPON TERMINATION . . . . . . . . . . . . . .	160
40	DECOMMISSIONING OF THE PROJECT . . . . . . . . . . . . . . . . . . . . . . . .	161
	IX. MISCELLANEOUS PROVISIONS
41	RELATIONSHIP OF PARTICIPANTS . . . . . . . . . . . . . . . . . . . . . . . . . . .	162
42	NOTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	163
43	OTHER PROVISIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	166
44	EXECUTION IN COUNTERPARTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	169
45	AMENDMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	170

EXHIBIT I Real Property

EXHIBIT II Annual Minimum Coal

EXHIBIT III Switchyard Facilities

EXHIBIT IV Ownership of Equipment

EXHIBIT V O&M of Equipment

EXHIBIT VI A&G Expenses

EXHIBIT VII Coal Allocation and Billing

EXHIBIT VIII Adjustment of Voting Requirements

EXHIBIT IX Fixed Fuel Expense

EXHIBIT X Variable Fuel Expense

iii

EXECUTION VERSION

PART I

PARTIES AND INTRODUCTORY MATTERS

1.0 PARTIES:

The parties to this Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement (“Agreement”) are: PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“PNM”); TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“TEP”); THE CITY OF FARMINGTON, NEW MEXICO, an incorporated municipality and a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Farmington”); M-S-R PUBLIC POWER AGENCY, a joint exercise of powers agency organized under the laws of the State of California (“M-S-R”); THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO, a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“LAC”); SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, a joint exercise of powers agency organized under the laws of the State of California (“SCPPA”); CITY OF ANAHEIM, a municipal corporation organized under the laws of the State of California (“Anaheim”); UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS, a political subdivision of the State of Utah (“UAMPS”); TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC., a Colorado cooperative corporation (“Tri-State”); and PNMR DEVELOPMENT AND MANAGEMENT CORPORATION, a New Mexico corporation (“PNMR-D”). The Parties, other than PNMR-D, are the participants in the San Juan Project, and are hereinafter sometimes referred to individually as a “Participant” and collectively as

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“Participants.” PNMR-D is being added as a Party to this Agreement in anticipation of its future acquisition of an interest in the San Juan Project, as provided for herein, and because PNMR-D will assume certain financial obligations under this Agreement.

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2.0 RECITALS: This Agreement is made with reference to the following facts, among others:

2.1 PNM is an electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.

2.2 TEP is an electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of Arizona.

2.3 Farmington operates a municipal electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.

2.4 M-S-R is a public entity engaged in the generation, transmission, purchase and sale of electric power and energy in the western United States for the benefit of its member public agencies.

2.5 LAC operates a municipal electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.

2.6 SCPPA is a public entity created to acquire, construct, finance, operate and maintain generation and transmission projects on behalf of its members.

2.7 Anaheim operates a municipal utility in the State of California engaged in the generation, transmission and distribution of electric power.

2.8 UAMPS is a public entity created to plan, finance, develop, acquire, construct, improve, better, operate and maintain projects, or ownership interests or capacity

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rights therein, for the generation, transmission and distribution of electric energy for the benefit of its members.

2.9 Tri-State is a cooperative corporation created pursuant to the laws of the State of Colorado. Tri-State’s primary functions involve the generation, transmission, transformation and sale of electricity to its member distribution cooperatives.

2.9(a) PNMR-D is a New Mexico corporation, a wholly owned subsidiary of PNM Resources, Inc. and an affiliate of PNM.

2.10 PNM and TEP each has an undivided one-half (1/2) ownership interest in the real property associated with the San Juan Project, which real property is described in Exhibit I, attached hereto and incorporated herein, and is identified therein as Parcels A through F.

2.11 PNM and TEP entered into the Coal Sales Agreement with San Juan Coal Company (“SJCC”), pursuant to which SJCC agreed to supply the San Juan Project with coal. PNM and TEP also entered into the Transportation Agreement with San Juan Transportation Company (“SJTC”) dated April 30, 1984, under which coal was transported from the La Plata Mine. Subsequently, PNM and TEP entered into the Underground Coal Sales Agreement with SJCC, pursuant to which SJCC agreed to supply coal to the San Juan Project beginning January 1, 2003. The Underground Coal Sales Agreement superseded and replaced the Coal Sales Agreement, except for certain provisions of the Coal Sales Agreement which survived through the provisions of the Coal Sales Agreement Buy Out Agreement. The Transportation Agreement was terminated effective December 31, 2002,

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except for certain provisions which survived through provisions of the Transportation Agreement Buy Out Agreement.

2.11(a) PNM entered into a new Coal Supply Agreement (“CSA”) for the supply of all the coal requirements for the San Juan Project from January 1, 2016 through June 30, 2022. PNM also entered into a Coal Combustion Residual Disposal Agreement (“CCRDA”), for the performance of all ash disposal activities for the San Juan Project over the term of the CSA and a Reclamation Services Agreement (“RSA”), for the performance of all reclamation obligations of the mines that have supplied coal for the San Juan Project from the RSA’s effective date until the full release of all reclamation and similar bonds associated with federal and state leases, agreements and permits. The anticipated effective date of the CSA, CCRDA and RSA is January 1, 2016.

2.11(b) In connection with the CSA, RSA and CCRDA becoming effective, PNM, TEP, SJCC and BHP Billiton New Mexico Coal, Inc., parent company to SJCC, agreed to terminate the UG-CSA and the CCBDA.

2.12 PNM contracted with the United States Department of the Interior, Bureau of Reclamation, under the Colorado River Storage Project Act to purchase 20,200 acre feet of water per year from Navajo Reservoir under Contract 14‑06‑400‑4821 dated April 11, 1968. Said contract was amended by an amendatory contract dated September 29, 1977, wherein the United States Department of the Interior, Bureau of Reclamation (i) acknowledged PNM’s assignment to TEP of an undivided one-half (1/2) interest in PNM’s rights and obligations imposed under the April 11, 1968, contract; and (ii) revised

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the amount of water available for consumptive use by the San Juan Project from the Navajo Reservoir from 20,200 acre feet per year to 16,200 acre feet per year. Upon expiration of the above-referenced contract with the United States Department of the Interior, Bureau of Reclamation, on December 31, 2005, water from the Navajo Reservoir is delivered to the San Juan Project under contractual arrangements with the Jicarilla Apache Nation. From time-to-time, contracts for surplus water supply may also be entered into by the Operating Agent for supply to the San Juan Project. Additional water for use at the San Juan Project is based on a Grant of Authority for 8,000 acre-feet of water, dated August 18, 1980, from Utah International (predecessor in interest to SJCC) to PNM and TEP.

2.13 The San Juan Project Co-Tenancy Agreement was executed as of February 15, 1972, effective as of July 1, 1969. The original Co-Tenancy Agreement was modified by joint action of PNM and TEP, as follows: Modification No. 1 on May 16, 1979, Modification No. 2 on December 31, 1983, Modification No. 3 on July 17, 1984, Modification No. 4 on October 25, 1984, Modification No. 5 on July 1, 1985, Modification No. 6 on April 1, 1993, Modification No. 7 on April 1, 1993, Modification No. 8 on September 15, 1993, Modification No. 9 on January 12, 1994 and Modification No. 10 on November 30, 1995 (the original of such Co-Tenancy Agreement, as amended by Modifications 1 through 10, is referred to herein as the “Co-Tenancy Agreement”).

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Modification No. 2 on December 31, 1983, Modification No. 3, on July 17, 1984, Modification No. 4 on October 25, 1984, Modification No. 5 on July 1, 1985, Modification No. 6 on April 1, 1993, Modification No. 7 on April 1, 1993, Modification No. 8 on September 15, 1993, Modification No. 9 on January 12, 1994 and Modification No. 10 on November 30, 1995 (the original of such Operating Agreement, as amended by Modifications 1 through 10, is referred to herein as the “Operating Agreement”).

2.15 A San Juan Project Construction Agreement was executed as of December 21, 1973, effective as of July 1, 1969, to govern the construction of the San Juan Project; this agreement was thereafter modified from time to time and was terminated in 1995 by action of PNM and TEP.

2.16 On May 16, 1979, TEP and PNM entered into an agreement whereby on that date TEP conveyed to PNM TEP’s 50 percent undivided ownership interest in Unit 4.

2.17 On November 17, 1981, PNM transferred an 8.475 percent undivided ownership interest in Unit 4 to Farmington.

2.18 On December 31, 1983, PNM transferred a 28.8 percent undivided ownership interest in Unit 4 to M-S-R.

2.19 On October 31, 1984, TEP transferred its 50 percent undivided ownership interest in Unit 3 to Alamito Company, which later changed its name to Century Power Company (“Century”).

2.20 On July 1, 1985, PNM transferred a 7.2 percent undivided ownership interest in Unit 4 to LAC.

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2.21 On July 1, 1993, Century transferred a 41.8 percent undivided ownership interest in Unit 3 to SCPPA.

2.22 On August 12, 1993, PNM transferred a 10.04 percent undivided ownership interest in Unit 4 to Anaheim.

2.23 On June 2, 1994, PNM transferred a 7.028 percent undivided ownership interest in Unit 4 to UAMPS.

2.24 On January 2, 1996, Century transferred an 8.2 percent undivided ownership interest in Unit 3 to Tri-State.

2.25 Farmington, M-S-R, LAC, SCPPA, Anaheim, UAMPS and Tri-State were classified as “Unit Participants” in the San Juan Project, pursuant to the Co-Tenancy Agreement.

2.26 As of April 29, 1994, PNM, TEP, Century, SCPPA, Farmington, M-S-R, LAC and Anaheim executed the San Juan Project Designated Representative Agreement (the “DR Agreement”) to implement the requirements of the federal Clean Air Act Amendments of 1990; the DR Agreement was thereafter accepted by UAMPS and Tri-State at the time of their respective purchases of ownership interests in the San Juan Project.

2.27 As of October 27, 1999, the Participants entered into the San Juan Project Participation Agreement (“Original San Juan PPA”). The purpose of the Original San Juan PPA was to amend and restate, and to replace in their entirety, the Co-Tenancy Agreement and the Operating Agreement and to set out in one instrument all of the matters previously included in the Co-Tenancy Agreement and the Operating Agreement.

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2.28 As of March 23, 2006, the Participants entered into an Amended and Restated San Juan Project Participation Agreement to amend and restate the Original San Juan PPA to reflect certain amendments agreed to by the Participants including, but not limited to, changes to the provisions of the Original San Juan PPA pertaining to fuel supply. Certain changes to the Amended and Restated San Juan Project Participation Agreement were subsequently accepted by FERC for filing as PNM Rate Schedule No. 144.

2.29 The Parties have executed the San Juan Project Restructuring Agreement (“Restructuring Agreement”) relating to the restructuring of ownership interests in the San Juan Project. On the same date, the Parties also executed the San Juan Decommissioning and Trust Funds Agreement (“Decommissioning Agreement”), which relates to decommissioning of the San Juan Project, and the Amended and Restated Mine Reclamation and Trust Funds Agreement (“Mine Reclamation Agreement”), which relates to reclamation of the San Juan Mine.

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3.0 AGREEMENT: The Parties, for and in consideration of the mutual covenants to be by them kept and performed, agree as follows.

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4.0 EFFECTIVE DATE AND TERMINATION:

4.1 Except as otherwise provided in Section 4.3, this Agreement shall become effective upon the effective date established by the FERC in its order accepting this Agreement for filing; provided that, if the FERC orders a hearing to determine whether this Agreement is just and reasonable, this Agreement shall not become effective until the date when an order has been issued by the FERC determining this Agreement to be just and reasonable without changes or modifications unacceptable to the Parties.

4.2 Following execution by all Parties, PNM shall file a copy of this Agreement with the FERC in a timely manner. In such filing, PNM shall request waiver of applicable FERC notice requirements in order to allow this Agreement to become effective consistent with the effective date provisions of the Restructuring Agreement. All other Parties shall support PNM’s filing by the prompt filing of a certificate or letter of concurrence or intervention in support of the filing or shall not take any action to oppose the filing of this Agreement.

4.3 Following an order by the FERC or any other regulatory agency having jurisdiction, if any, the Parties shall each review such order, letter or communication to determine if the FERC or any agency having jurisdiction has changed or modified a condition or conditions, deleted a condition or conditions, or imposed a new condition or conditions with regard to this Agreement; or has conditioned its approval of this Agreement upon changes or modifications to a condition or conditions, deletion of a condition or conditions or imposition of a new condition or conditions. The Party receiving such order,

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letter or communication shall promptly provide a copy of such order, letter or communication to the other Parties. Within fifteen (15) business days after receipt by the other Parties of the copy of the order, letter or communication, the Parties shall indicate to each other in writing their acceptance or rejection of this Agreement based upon any changes, modifications, deletions or new conditions required by the FERC or any agency having jurisdiction. A failure to notify within said fifteen (15) day period shall be the equivalent to a notification of acceptance. If any Party rejects this Agreement because the FERC or any agency having jurisdiction has modified a condition, deleted a condition or imposed a new condition in this Agreement, or has conditioned its approval on such a change, modification, deletion or new condition, the Parties will be deemed to have rejected this Agreement and they shall attempt, in good faith, to renegotiate the terms and conditions of this Agreement to resolve such changed, modified, deleted or new condition to the satisfaction of the Parties within one hundred twenty (120) days after the date of such order, letter or communication and thereafter to obtain requisite regulatory approval of such renegotiated agreement.

4.4 This Agreement shall continue in force and effect until July 1, 2022, unless otherwise agreed in writing by the Parties.

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5.0 DEFINITIONS: The following terms, when used herein with initial capitalization, and whether in the singular or the plural, shall have the meaning specified:

5.1 ACCOUNTING PRACTICE: Generally accepted accounting principles in accordance with FERC Accounts applicable to electric utility operations.

5.2 AGREEMENT: This Amended and Restated San Juan Project Participation Agreement, including all exhibits and attachments hereto, and as may be modified or amended from time to time.

5.3 AUDITING COMMITTEE: A committee which is described in Section 21.

5.4 AVAILABLE OPERATING CAPACITY: The maximum net electrical capacity of each installed and operating Unit which is available at any given time to the Participants at the 345 kV buses.

5.4(a) AVAILABLE PRE-EXISTING STOCKPILE TONS has the meaning provided for in Section 12.1(C)(1) of the CSA.

5.5 CAPACITY: Electrical rating expressed in megawatts (“MW”).

5.6 CAPITAL IMPROVEMENTS: Any property, land or land rights added to the San Juan Project or the substitution, replacement, enlargement or improvement of any Units of Property, structures, facilities, equipment, property, land or land rights constituting a part of the San Juan Project, which in accordance with Accounting Practice would be capitalized, and also including the costs of removal, salvage or disposal of any Units of Property being replaced or substituted.

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5.6(a) CCBDA means the Coal Combustion Byproducts Disposal Agreement between PNM, TEP and SJCC.

5.6(b) CCBDA TERMINATION AGREEMENT means the Coal Combustion Byproducts Disposal Agreement Termination and Mutual Release Agreement between SJCC, BHP Billiton, PNM and TEP.

5.6(c) CCR means ash and gypsum byproducts produced by the San Juan Project.

5.6(d) CCRDA means the new Coal Combustion Residuals Disposal Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016.

5.7 COAL SALES AGREEMENT: Agreement between PNM, TEP and SJCC executed on August 18, 1980, as amended or modified from time to time and which was replaced by the Underground Coal Sales Agreement. However, certain provisions of the Coal Sales Agreement survive through the provisions of the Coal Sales Agreement Buy Out Agreement dated August 31, 2001.

5.8 COAL SALES AGREEMENT BUY OUT AGREEMENT: Agreement between PNM, TEP and SJCC executed on August 31, 2001, as may be amended or modified from time to time.

5.8(a) COAL TONNAGE COMPONENT means coal tonnage categories as defined in the CSA and comprised of Pre-existing Stockpile Coal, Force Majeure Tons, Available Pre-existing Stockpile Tons, Tier 1 Tons and Tier 2 Tons.

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5.9 COMMON PARTICIPATION SHARE: Each Party’s percentage ownership interest as set forth in Section 6.2.6.

5.9(a) COMMON PARTICIPATION SHARE OF SHARED COAL INVENTORY means a Party’s share of equipment and facilities common to all of the Units (as shown in Section 6.2.6) multiplied by the sum of (i) coal tons stockpiled on SJCC’s property and (ii) coal tons stockpiled on the SJGS plant site.

5.10 CONTROL AREA: An area comprised of an electric system or systems bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedules with other control areas while maintaining frequency regulation of the interconnection.

5.11 COORDINATION COMMITTEE: A committee which is described in Section 18.

5.12 CO-TENANCY AGREEMENT: The agreement described in Section 2.13.

5.12(a) CSA means the new Coal Supply Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016, as it may be amended or replaced.

5.12(b) DECOMMISSIONING AGREEMENT means the San Juan Project Decommissioning and Trust Funds Agreement among the Parties executed concurrently with the Restructuring Agreement and effective on the Exit Date.

5.12(c) DEMAND CHARGE has the meaning provided for in Section 7.13.2.

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5.13 DR AGREEMENT: The agreement described in Section 2.26, as amended from time to time.

5.14 EMERGENCY COAL STORAGE PILE: The coal storage pile for the San Juan Project, sometimes referred to as the “minimum coal storage pile,” or as the “force majeure pile,” which is to be drawn upon when fuel deliveries are interrupted.

5.15 EMERGENCY SPARE PARTS: Spare parts or auxiliary equipment, the cost of which is capitalized, which are stocked for emergency use for the San Juan Project and which are not scheduled for periodic replacement.

5.16 ENERGY: The accumulated amount of power produced over a stated time interval, expressed in kilowatt hours (“kWh”) or megawatt hours (“MWh”).

5.17 ENGINEERING AND OPERATING COMMITTEE: A committee which is described in Section 19.

5.17(a) EXIT DATE means the date upon which the Exiting Participants transfer all of their respective rights, titles and interests in and to their Ownership Interests to PNM or PNMR-D, as provided in the Restructuring Agreement, and terminate their active involvement in the operation of the SJGS, except as expressly provided for in the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement; the Exit Date will be on or about December 31, 2017.

5.17(b) EXITING PARTICIPANTS means those Participants that will transfer all of their respective rights, titles and interests in and to their Ownership Interests to PNM or PNMR-D and terminate their active involvement in the operation of SJGS on the Exit

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Date, except as expressly provided for in the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement; the Exiting Participants are M-S-R, Anaheim, SCPPA and Tri-State.

5.18 FC LINE: That 345 kV transmission line between the San Juan generating station and the Four Corners generating plant.

5.19 FIXED FUEL EXPENSE: Those expenses itemized on Exhibit IX, attached hereto and incorporated herein.

5.20 FERC: The Federal Energy Regulatory Commission or any successor thereto.

5.21 FERC ACCOUNTS: The FERC Uniform System of Accounts prescribed for Public Utilities and Licensees (Class A and Class B). References in this Agreement to a specific FERC account number shall mean the number in effect as of the date of this Agreement and any successor account number.

5.21(a) FORCE MAJEURE TONS has the meaning provided for in Section 12.1(C)(3) of the CSA.

5.22 FUELS COMMITTEE: A committee which is described in Section 20.

5.22(a) LEGACY COSTS means those costs payable under Sections 8.2, 8.3 and 8.4 of the CSA.

5.23 MATERIALS AND SUPPLIES: Those materials and supplies, the cost of which is charged to FERC Account 154, which are stocked for use in the operation and maintenance of the San Juan Project.

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5.23(a) MINE RECLAMATION AGREEMENT means the Amended and Restated Mine Reclamation and Trust Funds Agreement among the Parties, executed concurrently with the Restructuring Agreement.

5.23(b) MINIMUM ANNUAL GENERATION (“MAG”) (expressed in MWh) means Net Maximum Capacity (“NMC”) (of Unit 3 or Unit 4, as applicable), and expressed in MW, multiplied by each Participant’s percentage Ownership Interest (“I”) in a Unit multiplied by 0.85 multiplied by (the Unit 3 Equivalent Availability Factor (“EAF”), as defined in the North American Electric Reliability Corporation’s Generating Availability Data System Data Reporting Instructions, for SCPPA and Tri-State or the Unit 4 EAF for M-S-R and Anaheim) multiplied by the total annual hours in the calendar year (“AH”). The AH in calendar year 2016 equals 8784 hours and the AH in calendar year 2017 equals 8760 hours. The foregoing is expressed in the following formula:

5.23(c) MINIMUM ANNUAL TONNAGE PURCHASE OBLIGATION (“MTO”) means Minimum Annual Generation multiplied by the Participant’s respective actual average net unit heat rate (“NUHR”), expressed in Btu/kWh, for the year, divided by two times the weighted average heat content (“HC”), expressed in Btu/Lb, of coal delivered by SJCC in the year. The foregoing is expressed in the following formula:

5.24 MINIMUM ANNUAL TONS: The quantities of coal, also defined as Minimum Annual Tons (“MAT”) in Section 8.2(F)7 of the Underground Coal Sales

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Agreement, and set forth in Exhibit H to the Underground Coal Sales Agreement, which amounts are shown on Exhibit II, attached hereto and incorporated herein.

5.25 MINIMUM NET GENERATION: The lowest net load at which each Unit can be reliably maintained in service on a continuous basis on coal fuel.

5.26 MONTHLY MINIMUM TONS: Monthly Minimum Tons (“MMT”) as also defined in Section 8.2(F)8 of the Underground Coal Sales Agreement, shall be allocated each year to each Participant pursuant to a monthly schedule approved annually by the Fuels Committee as provided in Section 20.3.3, such that the annual sum of each Participant’s Monthly Minimum Tons equals its Common Participation Share of MAT as defined in Section 8.2(F)7 of the Underground Coal Sales Agreement. In the event that a monthly allocation of MMT has not been approved by the Fuels Committee, MMT shall be allocated to each Participant based on Common Participation Share.

5.27 NET EFFECTIVE GENERATING CAPACITY: The maximum continuous ability of each Unit to produce power, less auxiliary power requirements.

5.28 NET ENERGY GENERATION: The Energy generated by each Unit which is available to the respective Participants at the 345 kV bus.

5.29 OPERATING ACCOUNT: The bank account(s) in the names of the Parties established by the Operating Agent pursuant to Section 28.

5.30 OPERATING AGENT: The Participant or other entity which has been selected by the Participants as the entity responsible for the operation and maintenance of the San Juan Project pursuant to this Agreement.

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5.31 OPERATING AGREEMENT: The agreement described in Section 2.14.

5.32 OPERATING EMERGENCY: An unplanned event or circumstance at the San Juan Project which reduces or may reduce the availability of Capacity or Energy from a Unit.

5.33 OPERATING FUNDS: Monies advanced to, and disbursed by, the Operating Agent on behalf of the Parties in accordance with this Agreement.

5.34 OPERATING INSURANCE: Policies of insurance secured or to be secured and maintained in accordance with Section 31.

5.35 OPERATING WORK: Engineering, contract preparation and administration, purchasing, repair, supervision, training, expediting, inspection, testing, protection, operation, use, management, replacement, retirement, reconstruction and maintenance of and for the benefit of the San Juan Project pursuant to this Agreement, including the administration of this Agreement, the Restructuring Agreement and of any Project Agreements, environmental compliance activities and the procurement of fuel and water and other necessary materials and supplies.

5.36 ORIGINAL SAN JUAN PPA: The San Juan Project Participation Agreement dated October 27, 1999.

5.36(a) OWNERSHIP INTEREST means a Party’s percentage undivided ownership interest in a Unit and in common equipment and facilities and as increased, decreased, acquired or transferred as provided in Sections 6.3 and 6.4 of the Restructuring Agreement, and rights incidental thereto.

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5.37 PARTICIPANT: PNM, TEP, Farmington, M-S-R, LAC, SCPPA, Anaheim, UAMPS or Tri-State.

5.38 PARTICIPANT COAL CONSUMPTION: Each Participant’s total San Juan Project coal consumption in tons as determined by the Operating Agent. A Participant’s Coal Consumption is comprised of its share of coal consumed in its Unit(s) plus its share of coal consumed for common loads, auxiliary loads and start-up for all Units.

5.39 PARTICIPATION SHARE: Each Participant’s percentage ownership interest in the various elements of the San Juan Project as set forth in Section 6.

5.39(a) PARTY or PARTIES: Each entity identified in the first sentence of Section 1.0.

5.39(b) PRE-EXISTING STOCKPILE COAL means coal that as of the effective date of the Restructuring Agreement is stockpiled on SJCC property.

5.40 PROJECT AGREEMENTS: Other than the Restructuring Agreement, Decommissioning Agreement and Mine Reclamation Agreement, which are not Project Agreements, Project Agreements will be this Agreement and such other agreements as are determined by the Coordination Committee to be necessary to define the rights and duties of the Participants with respect to the San Juan Project.

5.41 PROJECT COAL INVENTORY: The sum of coal in coal storage piles, silos, conveying systems, hoppers, and all other coal storage at the San Juan Project as accounted in FERC Account No. 151.

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5.42 PRUDENT UTILITY PRACTICE: Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in the light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Prudent Utility Practice is intended to be acceptable practices, methods or acts generally accepted in the industry, as such practices may be affected by special operational design characteristics of the San Juan Project, the quality and quantity of fuel delivered in accordance with the Underground Coal Sales Agreement or successor agreement, the rights and obligations of the Parties in accordance with this Agreement and any other special circumstances affecting the Operating Work.

5.42(a) REFINED COAL SUPPLY AGREEMENT means the Refined Coal Supply Agreement by and between San Juan Fuels, LLC and PNM dated June 21, 2013.

5.42(b) REMAINING PARTICIPANTS means those Parties that will continue participation, or acquire an Ownership Interest, in the Project on and after the Exit Date; the Remaining Participants are PNM, TEP, Farmington, UAMPS, LAC and PNMR-D.

5.42(c) RESTRUCTURING AGREEMENT means the San Juan Project Restructuring Agreement among the Parties.

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5.42(d) RSA means the new Reclamation Services Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016.

5.43 SAN JUAN PROJECT or SAN JUAN GENERATING STATION (“SJGS”): The four unit, coal-fired electric generation plant located in San Juan County, New Mexico, near Farmington, New Mexico. The San Juan Project includes all facilities, structures, transmission and distribution lines incident to the four-unit electric generating plant. The San Juan Project does not include distribution lines, transmission lines, equipment in the Switchyard Facilities or other facilities owned exclusively by a Party.

5.43(a) SJCC means San Juan Coal Company, a Delaware corporation, or its successors or assigns.

5.44 SWITCHYARD FACILITIES: The switchyard facilities required for the San Juan Project as shown by materials listed in Exhibit III, attached hereto and incorporated herein.

5.44(a) TIER 1 TONNAGE ALLOCATION means a schedule allocating Tier 1 Tons on a monthly basis based on the SJGS monthly planned coal consumption.

5.44(b) TIER 1 TONS means, with respect to: (i) each of 2016 and 2017, 5.75 million tons; (ii) each of 2018 and 2019, 2.8 million tons; (iii) each of 2020 and 2021, 2.65 million tons; and (iv) in 2022, 1.4 million tons.

5.44(c) TIER 2 TONS means all tons delivered to and accepted by SJGS in a year in excess of Tier 1 Tons.

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5.45 TOTAL MONTHLY COAL COST: The amount charged the Operating Agent each month in accordance with the Underground Coal Sales Agreement, the Coal Sales Agreement Buy Out Agreement and the Transportation Agreement Buy Out Agreement.

5.46 TRANSPORTATION AGREEMENT BUY OUT AGREEMENT: Agreement between PNM, TEP and San Juan Transportation Company (“SJTC”) executed on August 31, 2001, as may be amended or modified from time to time, terminated the Transportation Agreement with SJTC dated April 30, 1984.

5.46(a) UG-CSA TERMINATION AGREEMENT means the Underground Coal Sales Agreement Termination and Mutual Release Agreement among PNM, TEP, SJCC and BHP Billiton New Mexico Coal.

5.47 UNDERGROUND COAL SALES AGREEMENT: Agreement between PNM, TEP and SJCC executed on August 31, 2001, as amended or modified and as may be amended or modified from time to time.

5.48 UNIT: Unit 1, Unit 2, Unit 3 or Unit 4.

5.49 UNIT 1: The second operating unit of the San Juan Project, which was placed in commercial service on December 31, 1976 and which presently has a net capacity rating of 340 MW.

5.50 UNIT 2: The first operating unit of the San Juan Project, which was placed in commercial service on November 30, 1973 and which presently has a net capacity rating of 340 MW.

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5.51 UNIT 3: The third operating unit of the San Juan Project, which was placed in commercial service on December 31, 1979 and which presently has a net capacity rating of 496 MW.

5.52 UNIT 4: The fourth operating unit of the San Juan Project, which was placed in commercial service on April 27, 1982 and which presently has a net capacity rating of 507 MW.

5.53 UNITS OF PROPERTY: Property as described in the FERC’s list of units of property for use in connection with the Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act, contained in 18 CFR Part 116, in effect on the effective date of this Agreement, as thereafter modified or amended.

5.54 UTILITY PAYMENT STREAM (“UPS”): Those payments defined in Section 8.5(C) of the Underground Coal Sales Agreement.

5.55 VARIABLE FUEL EXPENSE: Those expenses itemized on Exhibit X, attached hereto and incorporated herein.

5.56 WATER CONTRACT(S): The applicable contract or contracts under which water is delivered to the San Juan Project, as more fully described in Section 2.12.

5.57 WILLFUL ACTION:

5.57.1 Action taken or not taken by a Party (or the Operating Agent), at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under

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a Project Agreement, which action is knowingly or intentionally taken or not taken with conscious indifference to the consequences thereof or with intent that injury or damage would probably result therefrom; or

5.57.2 Action taken or not taken by a Party (or the Operating Agent) at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under a Project Agreement, which action has been determined by final arbitration award or final judgment or judicial decree to be a material default under a Project Agreement and which action occurs or continues beyond the time specified in such arbitration award or judgment or judicial decree for curing such default, or if no time to cure is specified therein, occurs or continues beyond a reasonable time to cure such default; or

5.57.3 Action taken or not taken by a Party (or the Operating Agent), at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under a Project Agreement, which action is knowingly or intentionally taken or not taken with the knowledge that such action taken or not taken is a material default under a Project Agreement.

5.57.4 The phrase “employees having management or administrative responsibility,” as used in this Section 5.57, means employees of a Party who are responsible for one or more of the executive functions of planning, organizing,

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coordinating, directing, controlling and supervising such Party’s performance under a Project Agreement; provided however, that, with respect to employees of the Operating Agent acting in its capacity as such and not in its capacity as a Party, such phrase shall refer only to (i) the senior employee of the Operating Agent on duty at the San Juan Project who is responsible for the operation of the Units, and (ii) anyone in the organizational structure of the Operating Agent between such senior employee and an officer.

5.57.5 Willful Action does not include any act or failure to act which is merely involuntary, accidental or negligent.

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PART II

OWNERSHIP OF SAN JUAN PROJECT

6.0 OWNERSHIPS AND TITLES:

6.1 PNM and TEP, respectively, each has an undivided one-half (1/2) ownership interest in the real property interests described in Exhibit I as Parcels A through F.

6.2 Unless otherwise provided in Exhibit IV or Section 7.13, the Units and other facilities of the San Juan Project and Capital Improvements shall be owned and title held by the Parties in the following percentages:

6.2.1 For Units 1 and 2 and for all equipment and facilities directly related to Units 1 and 2 only, in accordance with the following percentages:

6.2.1.1 PNM: 50 percent

6.2.1.2 TEP: 50 percent

6.2.1.3 M‑S‑R: 0 percent

6.2.1.4 Farmington: 0 percent

6.2.1.5 Tri-State: 0 percent

6.2.1.6 LAC: 0 percent

6.2.1.7 SCPPA: 0 percent

6.2.1.8 Anaheim: 0 percent

6.2.1.9 UAMPS: 0 percent

6.2.1.10 PNMR-D: 0 percent

6.2.2 For Unit 3 and for all equipment and facilities directly related to Unit 3 only, in accordance with the following percentages:

6.2.2.1 PNM: 50 percent

6.2.2.2 TEP: 0 percent

6.2.2.3 M‑S‑R: 0 percent

6.2.2.4 Farmington: 0 percent

6.2.2.5 Tri-State: 8.2 percent

6.2.2.6 LAC: 0 percent

6.2.2.7 SCPPA: 41.8 percent

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6.2.2.8 Anaheim: 0 percent

6.2.2.9 UAMPS: 0 percent

6.2.2.10 PNMR-D: 0 percent

6.2.3 For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:

6.2.3.1 PNM: 38.457 percent

6.2.3.2 TEP: 0 percent

6.2.3.3 M‑S‑R: 28.8 percent

6.2.3.4 Farmington: 8.475 percent

6.2.3.5 Tri-State: 0 percent

6.2.3.6 LAC: 7.20 percent

6.2.3.7 SCPPA: 0 percent

6.2.3.8 Anaheim: 10.04 percent

6.2.3.9 UAMPS: 7.028 percent

6.2.3.10 PNMR-D: 0 percent

6.2.4 For equipment and facilities common to Units 1 and 2 only, in accordance with the following percentages:

6.2.4.1 PNM: 50 percent

6.2.4.2 TEP: 50 percent

6.2.4.3 M‑S‑R: 0 percent

6.2.4.4 Farmington: 0 percent

6.2.4.5 Tri-State: 0 percent

6.2.4.6 LAC: 0 percent

6.2.4.7 SCPPA: 0 percent

6.2.4.8 Anaheim: 0 percent

6.2.4.9 UAMPS: 0 percent

6.2.4.10 PNMR-D: 0 percent

6.2.5 For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:

6.2.5.1 PNM: 44.119 percent

6.2.5.2 TEP: 0 percent

6.2.5.3 M‑S‑R: 14.4 percent

6.2.5.4 Farmington: 4.249 percent

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6.2.5.5 Tri-State: 4.1 percent

6.2.5.6 LAC: 3.612 percent

6.2.5.7 SCPPA: 20.9 percent

6.2.5.8 Anaheim: 5.07 percent

6.2.5.9 UAMPS: 3.55 percent

6.2.5.10 PNMR-D: 0 percent

6.2.6 For equipment and facilities common to all of the Units in accordance with the following percentages:

6.2.6.1 PNM: 46.297 percent

6.2.6.2 TEP: 19.8 percent

6.2.6.3 M‑S‑R: 8.7 percent

6.2.6.4 Farmington: 2.559 percent

6.2.6.5 Tri-State: 2.49 percent

6.2.6.6 LAC: 2.175 percent

6.2.6.7 SCPPA: 12.71 percent

6.2.6.8 Anaheim: 3.10 percent

6.2.6.9 UAMPS: 2.169 percent

6.2.6.10 PNMR-D: 0 percent

6.2.7 San Juan Project equipment and facilities not included in Sections 6.2.1 through 6.2.6 which were in service as of May 16, 1979, remain in individual one-half (1/2) ownership, with each of PNM and TEP retaining title to an equal undivided one-half (1/2) interest therein; provided, however, that subsequent to the in-service date of Unit 4, PNM, on behalf of itself and the Participants to which PNM conveyed ownership interests and generation entitlements in the San Juan Project, shall have the right to use sixty-five percent (65%), and TEP, on behalf of itself and the Participants which succeeded to TEP-conveyed ownership interests and generation entitlements in the San Juan Project, shall have the right to use thirty-five percent (35%) of the real property associated with the San Juan Project,

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the water, the then existing oil for ignition and flame stabilization, and the use of the 345 kV switchyard capacity up to the combined installed capacity of Units 1, 2, 3 and 4, except as otherwise provided in Section 7, and except that, subject to Section 15.2.3, PNM and TEP shall each be entitled to use 50 percent (50%) of switchyard capacity in excess of the combined installed capacity of Units 1, 2, 3 and 4 for the San Juan Project.

6.2.8 Exhibit IV (a through h), attached hereto and incorporated herein, is a partial list of equipment and facilities of the San Juan Project and reflects the Parties’ ownership interests therein. This exhibit is to provide the Engineering and Operating Committee, the Auditing Committee, the Fuels Committee and the Coordination Committee with guidelines for carrying out their duties under this Agreement.

6.2.9 In areas where ownership of equipment and facilities is not clearly defined by Sections 6.2.1 to 6.2.7, the Engineering and Operating Committee shall make a determination of such ownership in accordance with Section 19. Disputes arising from such determination shall be resolved by the Coordination Committee in accordance with Section 18.

6.2.10 Materials and Supplies shall be owned by the Participants in proportion to their respective current investments in the Materials and Supplies.

6.3 Upon the effective date of this Agreement, the Emergency Coal Storage Pile shall be owned as follows:

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6.3.1 PNM: 73.297 percent

6.3.2 TEP: 19.8 percent

6.3.3 M‑S‑R: 0 percent

6.3.4 Farmington: 2.559 percent

6.3.5 Tri-State: 0 percent

6.3.6 LAC: 2.175 percent

6.3.7 SCPPA: 0 percent

6.3.8 Anaheim: 0 percent

6.3.9 UAMPS: 2.169 percent

6.3.10 PNMR-D: 0 percent

6.4 In the event that a Party transfers or assigns any of its rights, titles or interests in and to the San Juan Project in accordance with the terms and conditions of this Agreement, the Parties (including the transferee or assignee of a Party) shall jointly make, execute and deliver a supplement to this Agreement in recordable form which shall describe with particularity and in detail the rights, titles and interests of each Party following such transfer or assignment.

6.5 PNM and TEP own as tenants in common the Switchyard Facilities described in Exhibit III in equal, undivided one-half (1/2) interests.

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7.0 CAPITAL IMPROVEMENTS AND RETIREMENTS OF SAN JUAN PROJECT AND PARTICIPANTS’ SOLELY OWNED FACILITIES:

7.1 The Parties recognize that from time to time it may be necessary or desirable to make Capital Improvements to and retirements of facilities comprising the San Juan Project.

7.2 Any such Capital Improvements and retirements shall be noted by an appropriate revision in or supplement to the appropriate exhibits hereto attached.

7.3 The rights, titles and interests, including Participation Shares, of a Party in and to any Capital Improvements shall be as provided for the respective classes of property described in Section 6. Except as provided in Section 7.13, the Parties shall be obligated for the costs of such Capital Improvements in the same percentages as their Participation Shares.

7.4 All Capital Improvements, and a contingency allowance for capital expenditures necessitated by an Operating Emergency or otherwise deemed justifiable by the Operating Agent, shall be included in the annual capital expenditures budget. The Engineering and Operating Committee may authorize Capital Improvements not included in the annual capital expenditures budget; provided, that such Capital Improvements shall not exceed the sum of five hundred thousand dollars ($500,000) for each such Capital Improvement, unless also authorized by the Coordination Committee.

7.5 The Operating Agent shall submit to the Parties a forecast of cash requirements by months for Capital Improvements. Said forecast will be submitted on a

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yearly basis after final budget approvals have been made. A revised forecast shall be submitted when the capital expenditures budget is revised, or when significant changes in monthly expenditures from those previously forecast are anticipated. The Operating Agent shall be authorized to make additional expenditures related to Capital Improvements; provided, however, that such additional expenditures for Capital Improvements shall not exceed the sum of one hundred thousand dollars ($100,000) or cause the total expenditure limit contained in the capital expenditures budget to be exceeded, unless also authorized by the Engineering and Operating Committee, or by the Coordination Committee if the total expenditure for such Capital Improvement exceeds five hundred thousand dollars ($500,000).

7.6 In the event of the removal or retirement of any facilities comprising part of the San Juan Project, any proceeds realized from the salvage of such facilities shall be distributed to the Participants in accordance with their Participation Shares therein, or shall be applied on account of the Participant’s obligations to pay for Capital Improvements replacing facilities removed or retired. Units of Property retired from service shall be disposed of by the Operating Agent on the best available terms as soon as practicable.

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future expansion plans at the San Juan Project, (iii) impair or interfere with the contractual rights of another Party, or (iv) jeopardize the reliability of another Participant’s system. The Engineering and Operating Committee shall have authority to impose conditions on a Participant allowed to make such additions in order to protect the other Parties consistent with applicable rules and regulations of the FERC. Such facilities shall be and remain the sole and exclusive property of the Participant installing same until and unless the Coordination Committee determines that such facilities are necessary and beneficial for operation of the San Juan Project as a whole. In the event of such determination, the facilities shall be acquired as a part of the San Juan Project by the Remaining Participants and compensation shall be paid to the selling Participant by the Remaining Participants acquiring such interest based on the net book value of such facilities.

7.8 Each Participant shall have the right, at its own expense, to add protective relay or communication equipment to facilities solely owned by it, if the Participant determines the protective relay or communication equipment is needed for the protection of its electric system, provided the Engineering and Operating Committee approves the design of such additional equipment and determines that space is available therefor, and that such committee also determines that such additional facilities will not (i) infringe upon the rights of another Participant in the facilities, (ii) unreasonably interfere with future expansion plans at the San Juan Project, (iii) impair or interfere with the contractual rights of another Party, or (iv) jeopardize the reliability of another Participant’s system.

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7.9 Transportation and motorized equipment which is to be utilized by the Operating Agent for Operating Work may be purchased or leased by the Operating Agent upon receipt of the approval referred to in Section 19.3.4. Ownership of such purchased equipment and the purchase price thereof shall be allocated between and paid by the Participants in proportion to the percentages established in Section 6. Lease payments made by the Operating Agent for such leased equipment shall be apportioned between and paid by the Participants in accordance with Section 22.1. No allowance to the Operating Agent for administrative and general expense shall be included in or added to such lease payments for transportation and motorized equipment which, in lieu of acquiring such equipment by purchase, has been leased on a long-term basis.

7.10 Upon retirement of leased transportation and motorized equipment utilized for Operating Work, an amount, which shall be treated as a charge (or credit), shall be determined by multiplying the difference between the salvage value and the unamortized balance owing to the leasing company for each piece of such equipment by a fraction, the numerator of which is the sum of the monthly lease payments for such equipment charged to Operating Work and the denominator of which is the sum of all monthly lease payments made by the Operating Agent for such equipment. Such charge or credit shall be allocated among the Participants in accordance with the applicable percentages set forth in Section 22.

7.11 Administrative and general expenses which have been incurred by the Operating Agent which are applicable to authorized Capital Improvements, shall be applied

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monthly to construction costs incurred during the preceding month. A rate will be developed by the Operating Agent every three (3) years in conjunction with the administrative and general (“A&G”) expenses study referenced in Attachment A to Exhibit VI. The current methodology for calculating the A&G Ratio for Capital Improvements is set forth in Exhibit VI, Attachment E. If any Party believes that the method used in determining the A&G Ratio for Capital Improvements results in an unreasonable burden on such Party(ies), such Party(ies) may request that said method used in determining said ratio be submitted to the Auditing Committee for review in accordance with the procedures set out in Sections 22.6.1 through 22.6.4.

7.12 Excluded from the charges in Section 7.11 are expenses incurred under Section 36.2.

7.13 The provisions of this Agreement are modified by this Section 7.13.

7.13.1 The Remaining Participants are responsible for the costs of Capital Improvements pertaining to all equipment and facilities directly related to Unit 4 only, common to Units 3 and 4 only and common to all of the Units, invoiced after January 1, 2015, and the Exiting Participants have no Ownership Interest in such Capital Improvements. The Exiting Participants will have no responsibility for costs of the SNCR/balanced draft project to be placed on Units 1 and 4. Costs of Capital Improvements invoiced after January 1, 2015, are allocated to the Remaining Participants as follows:

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7.13.1.1 For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:

7.13.1.1.1 PNM: 64.482%


7.13.1.1.2 Farmington:	8.475%


7.13.1.1.3	LAC: 7.200%


7.13.1.1.4	UAMPS: 7.028%

7.13.1.1.5 PNMR-D: 12.815%

7.13.1.2 For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:


7.13.1.2.1	PNM: 64.482%


7.13.1.2.2	Farmington: 8.475%


7.13.1.2.3	LAC: 7.200%


7.13.1.2.4	UAMPS: 7.028%


7.13.1.2.5	PNMR-D: 12.815%

7.13.1.3 For equipment and facilities common to all of the Units in accordance with the following percentages:


7.13.1.3.1	PNM: 58.671%


7.13.1.3.2	TEP: 20.068%

7.13.1.3.3 Farmington: 5.076%


7.13.1.3.4	LAC: 4.309%

7.13.1.3.5 UAMPS: 4.203%

7.13.1.3.6 PNMR-D: 7.673%

7.13.2 For the period July 1, 2014, through December 31, 2017, the Exiting Participants will pay a charge (the “Demand Charge”) for the use of new Capital Improvements implemented on Unit 4, facilities common to Units 3 and 4, and facilities common to all Units.

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7.13.2.1 The total Demand Charge is six million two hundred thousand dollars ($6,200,000) of which five million three hundred fourteen thousand two hundred eighty-six dollars ($5,314,286) remains unpaid. The Demand Charge will be paid regardless of the output of Unit 3 or 4. The Exiting Participants will be invoiced by the Operating Agent for and will pay the unpaid balance of the Demand Charge in monthly amounts of no less than 1/36 ^th of the unpaid balance; provided, the sum of the monthly amounts which would have accrued between January 1, 2015 and the Effective Date will be paid within forty-five (45) days of the Effective Date.

7.13.2.2 The Exiting Participants will pay the Demand Charge as follows:

7.13.2.2.1 M-S-R: 71.650%

7.13.2.2.2 Anaheim: 25.000%

7.13.2.2.3 SCPPA: 2.800%

7.13.2.2.4 Tri-State: 0.550%

17.13.2.3 The Remaining Participants will be paid the Demand Charge as follows from July 1, 2014 through December 31, 2014:

7.13.2.3.1 PNM: 0.000%

7.13.2.3.2 TEP: 0.000%

7.13.2.3.3 Farmington: 55.6%

7.13.2.3.4 LAC: 22.200%

7.13.2.3.5 UAMPS: 22.200%

7.13.2.3.6 PNMR-D: 0.000%

7.13.2.4 The Remaining Participants will be paid the Demand Charge as follows from January 1, 2015 through December 31, 2017:

7.13.2.4.1 PNM: 0.000%

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7.13.2.4.2 TEP: 0.000%

7.13.2.4.3 Farmington: 17.24%

7.13.2.4.4 LAC: 22.20%

7.13.2.4.5 UAMPS: 22.20%

7.13.2.4.6 PNMR-D: 38.36%

7.13.2.5 With respect to any Demand Charges paid or received between July 1, 2014 and December 31, 2014, any Exiting Participant that made such a Demand Charge payment and any Remaining Participant that received a Demand Charge payment and did not return it will be credited the amount of that payment or receipt as follows: the amount of any such payment will be proportionately offset against the amount of the Demand Charge payment each such Exiting Participant is obligated to pay under Sections 7.13.2.1 through 7.13.2.4, and the amount of any such receipt by a Remaining Participant will be proportionately offset against the amount of the Demand Charge payment each such Remaining Participant is entitled to receive under Sections 7.13.2.1 through 7.13.2.4. The Demand Charge payments made by Exiting Participants to the Operating Agent between July 1, 2014, and December 31, 2014, were as follows: M-S-R - $634,614; Anaheim - $221,429; SCPPA - $24,800; and Tri-State - $4,871. The Demand Charge payments received by the Remaining Participants between July 1, 2014, and December 31, 2014, and not returned to the Operating Agent were as follows: Farmington - $492,457. For a Remaining Participant that returned Demand Charge payments received between July 1, 2014 and December 31, 2014, such Remaining Participant will receive a disbursement from the Operating Agent constituting the Remaining Participant’s entire

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proportionate share of Demand Charge payments as set forth in Sections 7.13.2.1, 7.13.2.3 and 7.13.2.4.

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8.0	WAIVER OF RIGHT TO PARTITION:

8.1 The Parties accept title to their respective interests in the San Juan Project, water rights, lands, land rights and improvements thereon as tenants in common, and agree that their interests therein shall be held in such tenancy in common for the duration of the term of this Agreement, including any extensions thereof. While this Agreement, including any extensions thereof, remains in force and effect, each Party agrees as follows:

8.1.1 That it hereby waives the right to partition the San Juan Project, water rights, lands, land rights or the improvements built thereon (whether by partitionment in kind or by sale and division of the proceeds thereof), and

8.1.2 That it will not resort to any action at law or in equity to partition (in either such manner) the San Juan Project, water rights, lands, land rights or the improvements built thereon and waives the benefits of all laws that may now or hereafter authorize such partition.

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9.0 BINDING COVENANTS:

9.1 Except as otherwise provided in Section 9.3, all of the respective covenants and obligations of each of the Parties set forth and contained in the Project Agreements shall bind and shall be and become the respective obligations of:

9.1.1 Each Party;

9.1.2 All mortgagees, trustees and secured parties under all present and future mortgages, indentures and deeds of trust, and security agreements which are or may become a lien upon any of the properties of each Party;

9.1.3 All receivers, assignees for the benefit of creditors, bankruptcy trustees and referees of a Party;

9.1.4 All other persons, firms, partnerships or corporations claiming through or under any of the foregoing; and

9.1.5 Any successors or assigns of any of those mentioned in Sections 9.1.1 to 9.1.4, inclusive,

and shall be obligations running with the Parties’ rights, titles and interests in the San Juan Project, with all of the rights, titles and interests (if any) of each Party in, to and under this Agreement and with their rights, titles and interests in the water rights, lands, land rights and the improvements thereon. It is the specific intention of this provision that all of such covenants and obligations shall be binding upon any party which acquires any of the rights, titles and interests of any of the Parties in the San Juan Project, in, to and under this Agreement, and/or in the water rights, lands, land rights or the improvements thereon, and

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that all of the above-described persons and groups shall be obligated to use such Party’s rights, titles and interests in the San Juan Project, in, to and under this Agreement, and in the water rights, lands, land rights and the improvements thereon, for the purpose of discharging its covenants and obligations under this Agreement.

9.2 The rights, titles and interests of each Party in the San Juan Project, its rights, titles and interests in, to and under this Agreement and its rights, titles and interests in and to the water rights, lands, land rights and improvements thereon, shall inure to the benefit of its successors and assigns.

9.3 Any mortgagee, trustee or secured party, or any receiver or trustee appointed pursuant to the provisions of any present or future mortgage, deed of trust, indenture or security agreement creating a lien upon or encumbering the rights, titles or interests of any Party in the San Juan Project, in, to and under this Agreement and/or in the water rights, lands, land rights or the improvements thereon, and any successor thereof by action of law or otherwise, and any purchaser, transferee or assignee of any thereof, shall not be obligated to pay any monies accruing on account of any of the obligations or duties of such Party under this Agreement incurred prior to the taking of possession or the initiation of foreclosure or other remedial proceedings by such mortgagee, trustee or secured party.

9.4 In the event that any or all of the provisions of this Section 9 shall not be legally effective as to any Party, or its mortgagees, trustees, secured parties, receivers, successors or assigns, then such Party shall not be deemed in violation of this Section 9 by reason thereof.

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9.5 Nothing in this Section 9 or in this Agreement shall be deemed to change any rights, titles or interests to water rights, lands, land rights and the improvements thereon.

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10.0 MORTGAGE AND TRANSFER OF PARTIES’ INTERESTS:

10.1 The Parties shall have the right at any time and from time to time to mortgage, create or provide for a security interest in or convey in trust their respective rights, titles and interests in the San Juan Project, their respective rights, titles and interests in, to and under a Project Agreement and/or their rights, titles and interests in the water rights, lands, land rights or the improvements to be built thereon to a trustee or trustees under deeds of trust, mortgages or indentures, or to secured parties under a security agreement, as security for their present or future bonds or other obligations or securities, and to any successors or assigns thereof without need for the prior consent of the other Parties, and without such mortgagee, trustee or secured party assuming or becoming in any respect obligated to perform any of the obligations of the Parties.

10.2 Any mortgagee, trustee or secured party under present or future deeds of trust, mortgages, indentures or security agreements of any of the Parties and any successor or assign thereof, and any receiver, referee, or trustee in bankruptcy or reorganization of any of the Parties, and any successor by action of law or otherwise, and any purchaser, transferee or assignee of any thereof may, without need for the prior consent of the other Parties, succeed to and acquire all the rights, titles and interests of such Party in the San Juan Project, in, to and under the Project Agreements and/or the rights, titles and interests of such Party in the water rights, lands, land rights and improvements thereon, and may take over possession of or foreclose upon said property, rights, titles and interests of such Party.

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10.3 Except as otherwise provided in Sections 10.1, 10.2 or 10.4 or, with respect to a transfer or assignment by a Party to another Party as provided in Section 11, no Party shall transfer or assign its respective rights, titles and interests in the San Juan Project, in, to and under this Agreement and/or in the water rights, land, land rights and the improvements thereon, without the prior written consent of the other Parties, which consent shall not be unreasonably withheld.

10.4 Each Party shall have the right to transfer or assign its respective rights, titles and interests in the San Juan Project, in, to and under this Agreement and/or in the water rights, land, land rights and the improvements thereon, without the need for prior consent of the other Parties, at any time to any of the following:

10.4.1 To any corporation or other entity acquiring all or substantially all of the property of such Party; or

10.4.2 To any corporation or entity into which or with which such Party may be merged or consolidated; or

10.4.3 To any corporation or entity the stock or ownership of which is wholly owned by a Party; or

10.4.4 To any corporation or other entity which owns all of the outstanding common stock or other ownership interest of a Party (its “Parent”); or

10.4.5 To any corporation or other entity the common stock or other ownership interest of which is wholly owned by the Parent of a Party.

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10.5 Except as otherwise provided in Sections 10.1, 10.2 and 9.3, any successor to the rights, titles and interests of a Party in the San Juan Project, to the rights, titles and interests of a Party in, to and under the Project Agreements and/or in the water rights, lands, land rights or improvements thereon shall assume and agree to fully perform and discharge all of the obligations hereunder of such Party, and such successor shall notify the other Parties in writing of such transfer, assignment or merger, and shall furnish to the other Parties evidence of such transfer, assignment or merger. Any such successor shall specifically agree in writing with the remaining Parties at the time of such transfer, assignment or merger that it will not transfer or assign any rights, titles and interests acquired from the assigning Party without complying with the terms and conditions of Section 11.

10.6 No Party shall be relieved of any of its obligations and duties to the other Parties by a transfer, assignment or merger under this Section 10 without the express prior written consent of the remaining Parties, which consent shall not be unreasonably withheld.

10.7 Except as otherwise provided in Section 10.5, any transfer, assignment or merger made pursuant to the provisions of this Section 10 shall not be subject to the terms and conditions set forth and contained in Section 11.

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11.0 RIGHTS OF FIRST REFUSAL:

11.1 The purpose of this Section 11 is to set forth the manner in which all existing or future rights of first refusal, pertaining to the transfer of interests in the San Juan Project, shall be exercised. Except as provided in Section 10, PNM has a right of first refusal with respect to the proposed transfer of any ownership interest in the San Juan Project by any Party and TEP has a right of first refusal with respect to PNM’s proposed transfer of an interest in Unit 1 or Unit 2 and associated common property. The existence of other rights of first refusal shall be as provided in other appropriate instruments. Nothing in this Section 11 shall be construed to limit or expand the rights of first refusal of any Party.

11.2 Except as provided in Section 10, should a Party desire to assign, transfer, convey or otherwise dispose of (hereinafter collectively referred to as “Assign”) its rights, titles and interests in the San Juan Project, or its rights, titles and interests in, to and under the Project Agreements, or its rights, titles and interests in the water rights, lands, land rights or the improvements thereon or any part thereof or interest therein (hereinafter referred to as “Transfer Interest”), to any person, company, corporation or governmental agency (hereinafter referred to as “Outside Party”), the Party desiring to Assign shall first make an offer to sell the Transfer Interest to a Party(ies) having a right of first refusal, on the basis of the applicable amount as set out in either Section 11.2.1 or Section 11.2.2:

11.2.1 Where the Outside Party proposes to purchase for a specified monetary amount, from the Party desiring to Assign, an interest only in the San Juan Project and/or in contract rights, water rights, lands, land rights and improvements

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associated therewith, the amount of (i) a bona fide written offer from an Outside Party ready, willing and able (subject to obtaining any required regulatory approvals) to purchase the Transfer Interest; or, in the absence of a bona fide written offer, (ii) a purchase price set out in a bona fide purchase and sale agreement between the Party desiring to Assign and an Outside Party ready, willing and able (subject to obtaining any required regulatory approvals) to purchase the Transfer Interest; or

11.2.2 Where the Outside Party proposes to purchase from the Party desiring to Assign, (i) as part of a non-monetary offer (such as in the case of an asset swap) or (ii) when a segregated value for the Transfer Interest is not available (such as in the case of a bundled or packaged sale of assets), or (iii) where the Outside Party proposes to purchase an interest not only in the San Juan Project and/or in contract rights, water rights, lands, land rights and improvements associated therewith, but also in other property of the Party desiring to Assign, the purchase price shall be the fair market value of the Transfer Interest. As used herein, the term “fair market value” means the amount of money which a purchaser, willing but not obligated to buy the property, will pay to an owner, willing but not obligated to sell it, taking into consideration all of the uses to which the Transfer Interest is adapted and might in reason be applied.

11.3 At least three (3) months prior to its intended date to Assign, and after its receipt of a bona fide written offer, or execution of a bona fide purchase and sale agreement,

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of the type described in Section 11.2, the Party desiring to Assign its Transfer Interest shall serve written notice of its intention to do so upon the Party(ies) having a right of first refusal, in accordance with Section 42. Such notice shall: (i) have attached as an exhibit a copy of the bona fide offer of an Outside Party or of the bona fide purchase and sale agreement between the Outside Party and the Participant desiring to Assign (an “Outside Offer”); and (ii) shall contain a statement of the approximate proposed date to Assign.

11.4 The Party(ies) having the right of first refusal shall signify its (their) desire to purchase the entire Transfer Interest, or not purchase the entire Transfer Interest, by serving written notice of its (their) intention upon the Participant desiring to Assign pursuant to Section 42 within sixty (60) days after such service pursuant to Section 11.3 of the written notice of intention to Assign. Failure by a Party to serve notice as provided hereunder within the time period specified shall be conclusively deemed to be notice of its intention not to purchase the Transfer Interest.

11.5 When intention to purchase the entire Transfer Interest has been indicated by notices duly given hereunder by the Party(ies) desiring to purchase the Transfer Interest, the affected Parties shall thereby incur the following obligations:

11.5.1 The Party desiring to Assign and a Participant desiring to purchase the Transfer Interest shall be obligated to proceed in good faith and with diligence to obtain all required authorizations and approvals to Assign;

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11.5.2 The Party desiring to Assign shall be obligated to obtain the release of any liens imposed by or through it upon any part of the Transfer Interest and to Assign the Transfer Interest at the earliest practicable date thereafter; and

11.5.3 A Party desiring to purchase the Transfer Interest shall be obligated to perform all terms and conditions required of it to complete the purchase of the Transfer Interest.

The purchase of the Transfer Interest shall be fully consummated within six (6) months following the date upon which all notices required to be given under this Section 11 have been duly served, unless the Party is then diligently pursuing applications to appropriate regulatory bodies (if any) for required authorizations to effect such assignment or is then diligently prosecuting or defending appeals from orders entered or authorizations issued in connection with such applications.

11.6 If the intention to purchase the entire Transfer Interest has not been indicated by notices given within the time periods specified in this Section 11 by a Party desiring to purchase the Transfer Interest, the Party desiring to Assign shall be free to Assign all, but not less than all, of its Transfer Interest to the Outside Party that made the Outside Offer, upon the terms and conditions set forth in the Outside Offer. If such assignment of the entire Transfer Interest to the Outside Party is not completed within three (3) years after the approximate proposed date to Assign specified in the notice given pursuant to Section 11.3, the Party desiring to Assign its Transfer Interest must, unless it is then diligently pursuing its applications to appropriate regulatory bodies (if any) for required authorizations to effect

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such assignment, or is then diligently prosecuting or defending appeals from orders entered or authorizations issued in connection with such applications, give another complete new right of first refusal to the Party(ies) desiring to purchase pursuant to the provisions of this Section 11, before such Party shall be free to Assign a Transfer Interest to said Outside Party.

11.7 No assignment of a Transfer Interest, whether to another Party or to an Outside Party, shall relieve the assigning Party from full liability and financial responsibility for performance after any such assignment: (i) of all obligations and duties incurred by such Party prior to such assignment under the terms and conditions of the Project Agreements; and/or (ii) of all obligations and duties provided and imposed after such assignment upon such assigning Party under the terms and conditions of the Project Agreements, unless and until the assignee shall agree in writing with the remaining Parties to assume the obligations and duties of a Party hereunder; provided further, however, that such assignor shall not be relieved of any of its obligations and duties by an assignment under this Section 11, without the express prior written consent of the remaining Parties, which consent shall not be unreasonably withheld.

11.8 Any transferee, successor or assignee, or any party who may succeed to the Transfer Interest pursuant to this Section 11, shall specifically agree in writing with the remaining Parties at the time of such transfer or assignment that it will not transfer or assign all or any portion of the Transfer Interest so acquired without complying with the terms and conditions of this Section 11.

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11.9 The provisions of Section 11.8 shall not be applicable to any assignment of a Transfer Interest by one Party to another Party, provided that payment in full of such Transfer Interest, as defined in Section 11, has been made by the Party who is the assignee thereof.

11.10 A Party may, for the purpose of financing its interest in pollution control systems and facilities at the San Juan Project, sell, transfer or convey such interests pursuant to the New Mexico Pollution Control Revenue Bond Act, and any such sale, transfer or conveyance shall not be deemed as an assignment, transfer, conveyance or other disposal within the meaning of this Section 11.

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12.0 RIGHTS OF PNM AND TEP IN WATER AND COAL:

12.1 If, pursuant to the terms and conditions of the Underground Coal Sales Agreement, or the sublease dated August 18, 1980 (as amended to date and as such sublease may be amended from time to time), between Western Coal Company and Utah International, Inc. or their successors (“Sublease”), PNM and TEP succeed to any interest in coal lands, coal leases, water rights, or other property, the rights, titles and interests of PNM and TEP therein shall be held as tenants in common, with each of PNM and TEP having an equal undivided one-half (1/2) interest therein, and such rights, titles and interests shall be subject to all the terms and conditions set forth and contained in this Agreement.

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13.0 SEVERANCE OF IMPROVEMENTS:

13.1 All facilities, structures, improvements, equipment and property of whatever kind and nature constructed, placed or affixed on the rights-of-way, easements, patented lands, fee lands and leased lands as part of, or as Capital Improvements, to the San Juan Project, as against all parties and persons whomsoever (including, without limitation, any party acquiring any interest in the rights-of-way, easements, patented, fee or leased lands or any interest in or lien, claim or encumbrance against any of such facilities, structures, improvements, equipment and property of whatever kind and nature) shall be deemed to be and remain personal property of the Parties, not affixed to the realty.

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PART III

ENTITLEMENTS TO OUTPUT OF SAN JUAN PROJECT

14.0 ENTITLEMENT TO CAPACITY AND ENERGY:

14.1 Subject to the provisions of Section 16, the Participants shall be entitled to the Net Effective Generating Capacity of each of Unit 1, Unit 2, Unit 3 and Unit 4 in proportion to their respective Participation Shares. Each Participant shall be entitled to schedule its Energy up to the Available Operating Capacity.

14.2 The Operating Agent shall keep the system dispatcher of each Participant advised of the Available Operating Capacity.

14.3 When a Participant’s request for its share of the Available Operating Capacity necessitates the operation of a Unit, each Participant shall schedule for its account not less than its share of Minimum Net Generation. If, however, a Participant has scheduled an amount of Energy in excess of its share of the Minimum Net Generation, the other Participants shall be allowed to reduce their scheduled Energy to an amount that will maintain the Unit at the Minimum Net Generation level.

14.4 The delivery of Energy from the San Juan Project shall be scheduled by each Participant in advance with the Operating Agent and accounted for on the basis of integrated hourly actual generation, all in accordance with any operating procedures which may be established or approved by the Engineering and Operating Committee. Such operating procedures shall provide for modifying such schedules to meet the needs of day-to-day and hour-by-hour operation, including emergencies on a Participant’s system.

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14.5 The Operating Agent shall, to the extent possible, generate Energy at the San Juan Project in accordance with schedules submitted by each Participant, as such schedules may be revised from time to time, as long as such schedules do not jeopardize the operation of the San Juan Project.

14.6 The Participants shall revise their schedules in the event of an Operating Emergency or other incident beyond the control of the Operating Agent to reflect the actual Energy available from the San Juan Project during the period of the Operating Emergency or incident.

14.7 The Energy generated at the San Juan Project shall be controlled within PNM’s Control Area; provided, that such control shall not diminish the rights of any Participant to receive its entitlement of Energy from the San Juan Project.

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15.0 CAPACITY ALLOCATION OF SWITCHYARD FACILITIES:

15.1 The electrical capacity in the Switchyard Facilities shall be made available to PNM and TEP in the manner and in the amounts as set forth in Section 6.2.7. For the purposes of this Agreement, the FC Line shall be considered a part of the Switchyard Facilities.

15.1.1 The transmission capacity of the FC Line shall be measured at the Four Corners terminal. PNM and TEP each shall be entitled to fifty percent (50%) of the designated FC Line Capacity.

15.1.2 The transmission capacity of the FC Line termination and other contract matters concerning the Four Corners Project shall be handled individually by PNM and TEP.

15.2 The points of attachment to the San Juan 345 kV Switchyard Facilities for the purposes of this Section 15 are:

No. 1: TEP/PNM No. 1 345 kV transmission line;

No. 2: TEP/PNM No. 2 345 kV transmission line;

No. 3: PNM/TEP Four Corners Generating Plant 345 kV switchyard (through the FC Line);

No. 4: PNM’s WW 345 kV transmission line;

No. 5: PNM’s OJ 345 kV transmission line;

No. 6: Colorado Public Service Company/Western Area Power Administration/Tri-State Rifle 345 kV transmission line;

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No. 7: Western Area Power Administration-Shiprock 345 kV transmission line.

15.2.1 The Participants collectively shall not schedule more Power and Energy through any of the foregoing individual points of attachment than the established rating of that facility.

15.2.2 The Participants’ individual transmission capacity rights into or out of the Switchyard Facilities attachment points shall be the same as the ownership or contract rights of the Participant(s) in the attached facility up to the limits specified in this Section 15.

15.2.3 Any transmission capacity in the Switchyard Facilities specified to be available in Section 15.2.1 or otherwise determined to be available by the Engineering and Operating Committee, but not allocated to the individual Participants under Section 15.2.2, shall be declared “excess capacity” by the Engineering and Operating Committee. The Engineering and Operating Committee shall allocate such excess transmission capacity to PNM or TEP or such Participants having an ownership interest in the Switchyard Facilities, upon request in the amount requested for specified periods of time to the extent and for such time as the Engineering and Operating Committee finds such excess capacity to be available.

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16.0 USE OF FACILITIES DURING CURTAILMENTS:

16.1 If the Net Effective Generating Capacity of all Units is reduced because of factors (including, but not limited to, equipment failures, scheduled or unscheduled outages, fuel or fuel deliveries, water supply, air quality limitations) which commonly influence the total output of all Units, each Participant’s entitlement to Capacity during such period shall be reduced in proportion to the percentages specified in Section 6.2.6 during each hour of such curtailment unless otherwise specified in a separate agreement.

16.2 If factors which influence the operation of a Unit cause a curtailment of that Unit, then the capacity entitlement from that Unit for each Participant in that Unit shall be in proportion to the Participant’s Participation Share of that Unit.

16.3 If, because of factors which influence the operation solely of Units 1 and 2, or solely of Units 3 and 4, there shall be a curtailment of Units 1 and 2, or of Units 3 and 4, as the case may be, the curtailment for each Participant in Units 1 and 2, or Units 3 and 4, shall be allocated in proportion to the percentages specified in Sections 6.2.4 and 6.2.5, respectively.

16.4 To the extent that a curtailment results from scarcity of resources and not from mechanical or legal limitations, Participants may agree in writing to modify their schedules to allocate the use of such resources to such Unit(s) or to such times as to make the most efficient use thereof, consistent with Prudent Utility Practice, during the pendency of such curtailment. Notwithstanding the provisions of Section 23.2, the Operating Agent shall, during such curtailments, account for coal inventory on a Participant by Participant

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basis. Upon the conclusion of such curtailment, the provisions of Section 23.2 shall apply to any remaining coal inventory.

16.5 Curtailment of the transmission capacity in the Switchyard Facilities shall be allocated to the Participants in the manner and in the amounts as set forth in Section 6.2.7.

16.6 No Party shall exercise its rights relating to the San Juan Project so as to endanger or unreasonably interfere with the operation of the San Juan Project or the right of any other Party to use its share of Capacity and Energy from the San Juan Project.

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17.0 START-UP AND AUXILIARY POWER AND ENERGY REQUIREMENTS:

17.1 Each Participant shall be obligated to provide its Participation Share of the Energy requirements to start up and operate each Unit, and such requirements shall be provided by the Participants based upon the Participant’s percentage of operating costs in accordance with Section 22.1. Appropriate metering facilities shall be installed to assure measurement of such Energy. Such requirements for Energy shall be scheduled in advance by the Operating Agent in accordance with operating procedures approved by the Engineering and Operating Committee.

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PART IV

ADMINISTRATION

18.0 COORDINATION COMMITTEE:

18.1 As a means of securing effective cooperation and interchange of information and of providing consultation on a prompt and orderly basis among the Parties in connection with various administrative and technical problems which may arise from time to time under this Agreement, the Coordination Committee shall remain in existence during the term of this Agreement. Except as otherwise expressly provided in this Agreement, the Coordination Committee shall have no authority to modify any of the provisions of this Agreement.

18.2 The Coordination Committee shall consist of one representative from each Party who shall be an officer or other duly authorized representative of a Party. Any of the Parties may designate an alternate or substitute to act as its representative on the Coordination Committee in the absence of the regular representative on the Coordination Committee or to act on specified occasions or with respect to specified matters. Each Party shall notify the other Parties promptly, in writing, of the designation of its representative and alternate representative on the Coordination Committee and of any subsequent changes in such designations. The chairperson of the Coordination Committee shall be a representative employed by the Operating Agent.

18.3 The Coordination Committee shall have the following functions and responsibilities:

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18.3.1 Provide liaison between and among the Parties.

18.3.2 Exercise general supervision over the Engineering and Operating Committee, the Fuels Committee and the Auditing Committee.

18.3.3 Consider and act upon all matters referred to the Coordination Committee by the Engineering and Operating Committee, the Fuels Committee and the Auditing Committee.

18.4 Any action or determination of the Coordination Committee shall require a vote of the Participants or Remaining Participants in accordance with Sections 18.4.1, 18.4.2, 18.4.3 or 18.4.4. A Participant’s Coordination Committee representative shall be entitled to vote on all matters except those actions or determinations which relate solely to a Unit or to common property in which such Participant does not have a Participation Share or as provided in Section 35.4.1. If a Participant’s or Remaining Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majorities for actions or determinations specified in Sections 18.4.1, 18.4.2, 18.4.3 and 18.4.4 shall be adjusted in proportion to the number of Participants or Remaining Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII, attached hereto and incorporated herein. Maintenance scheduling and operation during periods of curtailment of the total San Juan Project are not matters which relate solely to a Unit, but are deemed to be matters affecting all Units.

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18.4.1 Except as provided in Sections 18.4.2, 18.4.3 and 18.4.4, any actions or determinations brought before the Coordination Committee shall require the following vote:

(a) More than a sixty-six and two thirds percent (66 2/3%) majority of the Participation Shares of the Participants in a Unit or common property as defined in Section 6.2; and

(b) More than a sixty-six and two thirds percent (66 2/3%) majority of the number of individual Participants having a Participation Share in a Unit or common property as defined in Section 6.2.

18.4.2 Any action or determination of the Coordination Committee related to common property as set forth in Section 6.2.6 and involving an expenditure greater than five million dollars ($5,000,000) shall require the following vote:

(a) More than an eighty-two percent (82%) majority of the Common Participation Shares of the Participants; and

(b) A minimum of sixty-six and two thirds percent (66 2/3%) majority of the number of the individual Participants.

18.4.3 Any action or determination of the Coordination Committee regarding any amendment of the CSA, replacement of the CSA with a new agreement or any interim coal pricing agreement related to the CSA (or its successor) shall require the following vote:

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(a) More than an eighty-two percent (82%) majority of the percentages, as set forth in Section 7.13.1.3, of the Remaining Participants; and

(b) A minimum of sixty-six and two thirds percent (66 2/3%) majority of the number of individual Remaining Participants, as set forth in Section 7.13.1.3.

18.4.4 For purposes of the application of the double voting procedures set out in Sections 18.4.1 and 18.4.2 pertaining to Capital Improvements on all equipment and facilities directly related to Unit 4 only, common to Units 3 and 4 only and common to all of the Units, (i) the percentages and the number of individual Remaining Participants shall be as provided in Section 7.13.1; and (ii) the Exiting Participants shall have no vote.

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representatives may, by prior arrangement with the chairperson of the Coordination Committee, attend a meeting of the Coordination Committee by conference call or video conferencing. A Coordination Committee representative who is unable to attend a meeting of the Coordination Committee may vote in absentia by delivering to the chairperson of the Coordination Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

18.6 Except for matters subject to the voting requirements of Section 18.4.3, in the event the Coordination Committee fails to reach agreement on any matter, which such committee is authorized to determine, approve or otherwise act upon after a reasonable opportunity to do so, then the Operating Agent shall be authorized and obligated to take such reasonable and prudent action, consistent with Prudent Utility Practice, as is necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree.

18.7 In the event the Coordination Committee fails to reach agreement on a matter subject to the voting requirements of Section 18.4.3, then an impasse shall be deemed to exist and the Participant which is a signatory to the CSA then in effect shall have the obligation and the responsibility, consistent with Prudent Utility Practice, to maintain a supply of coal to the San Juan Project.

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19.0 ENGINEERING AND OPERATING COMMITTEE:

19.1 The Engineering and Operating Committee shall remain in existence during the term of this Agreement. Except as expressly provided in this Agreement, the Engineering and Operating Committee shall have no authority to modify any of the provisions of this Agreement.

19.2 The Engineering and Operating Committee shall consist of up to two representatives from each Party who shall collectively have one vote. Any of the Parties may designate an alternate or substitute to act as its representative on the Engineering and Operating Committee in the absence of a regular representative on the Engineering and Operating Committee or to act on specified occasions or with respect to specified matters. Each Party shall notify the other Parties promptly, in writing, of the designation of its representatives and alternate representative on the Engineering and Operating Committee and of any subsequent change in the designation. The chairperson of the Engineering and Operating Committee shall be a representative employed by the Operating Agent.

19.3 The Engineering and Operating Committee shall have the following functions and responsibilities:

19.3.1 Review and approve the following items related to the performance of Operating Work.

19.3.1.1 Capital Improvements and the annual Capital Improvements budget.

19.3.1.2 The annual staffing table.

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19.3.1.3 The annual operation and maintenance budget.

19.3.1.4 Such written statements of operating or maintenance procedures as may be submitted to the Engineering and Operating Committee.

19.3.1.5 The planned annual maintenance schedule.

19.3.1.6 The policies for establishing the Emergency Spare Parts inventory.

19.3.1.7 The policies for establishing the inventory for Materials and Supplies.

19.3.1.8 The statistical and administrative reports, budgets and information and other similar records, and the form thereof, to be kept and furnished by the Operating Agent, in accordance with Section 28.3.15 (excluding accounting records used internally by the Operating Agent for the purpose of accumulating financial and statistical data, such as books of original entry, ledgers, work papers and source documents).

19.3.1.9 The determination of Net Effective Generating Capacity, Minimum Net Generation and Net Energy Generation of the San Juan Project, based upon recommendations of the Operating Agent.

19.3.1.10 The principles and procedures for establishing communication channels among Parties.

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19.3.1.11 The operating procedures for performance and efficiency testing.

19.3.1.12 The operating procedures for maintaining complete and accurate Capacity and Energy accounting.

19.3.1.13 The Operating Agent’s estimate and analysis of the total expenditures resulting from an Operating Emergency, as provided in Section 29.7.

19.3.1.14 The results and expenditures of programs and contracts on environmental control and data collection for which the Operating Agent has contracted.

19.3.2 Establish procedures for the operation of the San Juan Project during any period of curtailed operations which reduces or may reduce the Net Effective Generating Capacity.

19.3.3 Except for an Operating Emergency, as provided in Section 29, designate a construction agent responsible for the design, construction and acquisition of Capital Improvements.

19.3.4 Approve the list of transportation and motorized equipment to be purchased or leased by the Operating Agent for use in the performance of Operating Work.

19.3.5 Perform such other functions and responsibilities as may be assigned to it from time to time by the Coordination Committee.

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19.4 Any action or determination of the Engineering and Operating Committee shall require a vote of the Participants or Remaining Participants, in the manner provided for in Sections 18.4.1, 18.4.2 and 18.4.4. A Participant’s Engineering and Operating Committee voting representative shall be entitled to vote on all matters except those actions or determinations which relate solely to a Unit or to common property in which such Participant does not have a Participation Share or as provided in Section 35.4.1. If a Participant’s or Remaining Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majorities for actions or determinations specified in Sections 18.4.1, 18.4.2 and 18.4.4 shall be adjusted in proportion to the number of Participants or Remaining Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII. Maintenance scheduling and operation during periods of curtailment of the total San Juan Project are not matters which relate solely to a Unit, but are deemed to be matters affecting all Units.

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such action or determination subsequently shall be reduced to writing. Engineering and Operating Committee representatives may, by prior arrangement with the chairperson of the Engineering and Operating Committee, attend a meeting of the Engineering and Operating Committee by conference call or video conferencing. An Engineering and Operating Committee representative who is unable to attend a meeting of the Engineering and Operating Committee may vote in absentia by delivering to the chairperson of the Engineering and Operating Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

19.6 In the event that less than a requisite majority of the Engineering and Operating Committee is obtained, the matter shall be referred to the Coordination Committee for decision upon the request of any Participant’s or Remaining Participant’s, as applicable, Engineering and Operating Committee representative.

19.7 In the event the Engineering and Operating Committee fails to reach agreement on any matter which such committee is authorized to determine, approve or otherwise act upon after a reasonable opportunity to do so, then the Operating Agent shall be authorized and obligated to take such reasonable and prudent action, consistent with Prudent Utility Practice, as is necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree.

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20.0 FUELS COMMITTEE:

20.1 As a means of establishing a centralized forum to facilitate the timely and candid consideration and discussion between all Parties of policies and issues associated with the procurement of coal for the San Juan Project, there is hereby established a Fuels Committee, which shall remain in existence during the term of this Agreement. The Parties do not intend that the operation of the Fuels Committee shall affect the day-to-day fuels-related operational responsibilities of the Operating Agent, except as otherwise specifically provided in this Section 20. The Fuels Committee shall have no authority to modify any of the provisions of this Agreement.

20.2 The Fuels Committee shall consist of one representative from each Party. Any of the Parties may, by written notice to the other Parties, designate an alternate or substitute to act as its representative on the Fuels Committee in the absence of the regular representative on the Fuels Committee or to act on specified occasions or with respect to specified matters. Each Party shall notify the other Parties promptly in writing of the designation of its representative on the Fuels Committee and of any subsequent change in such designation. The chairperson of the Fuels Committee shall be a representative employed by the Participant that is a signatory to the CSA. The Fuels Committee shall meet regularly, but in no event less than semiannually. Special meetings shall be called by the chairperson if requested in writing by any three (3) Parties.

20.3 Subject to Section 20.7, the Fuels Committee shall have the following functions and responsibilities:

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20.3.1 To conduct studies, or cause studies to be conducted, regarding criteria pertaining to the acquisition of coal supplies and the negotiation and approval of coal agreements. Such studies and recommendations may include, but are not limited to:

20.3.1.1 Annual fuel supply budgets

20.3.1.2 Coal cost

20.3.1.3 Coal delivery rates and minimum take obligations

20.3.1.4 Coal quality

20.3.1.5 Contract terms

20.3.1.6 Economic requirements

20.3.1.7 Negotiation strategies

20.3.1.8 Potential coal suppliers

provided, however, that prior to any such study being conducted, the Party(ies) desiring that the study be performed shall have made suitable arrangements therefor, including payment arrangements with the provider of the study. Nothing in this Section 20.3 shall be construed to require the Operating Agent or any Party to undertake any uncompensated or unfunded study which it would not otherwise perform.

20.3.2 To obtain input from all Parties regarding individual criteria and economic requirements necessary to vote on matters entrusted to the Fuels

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Committee or to make collective recommendations to the Coordination Committee.

20.3.3 To receive progress reports from and provide recommendations to negotiators acting on behalf of Parties in the negotiation and administration of coal supply and related agreements.

20.3.5 To provide regular progress reports to the Engineering and Operating and to the Coordination Committees, as requested by such committees.

20.3.6 To establish the amount of coal to be maintained in the Emergency Coal Storage Pile.

20.3.7 To establish operating procedures for delivery of coal to the Emergency Coal Storage Pile.

20.3.8 To establish procedures for the determination of Participant Coal Consumption.

20.3.9 To perform such other functions and responsibilities as are identified in Sections 23.4.2.8, and 23.4.2.10.

20.3.10 To perform such other functions and responsibilities as may be assigned to it from time to time by the Coordination Committee.

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negotiations or discussions concerning coal supply or related matters for the San Juan Project with SJCC or any other coal supplier or potential supplier; provided, however, that nothing herein shall be construed to prevent the Operating Agent or the Participant which is a signatory to the CSA, in the conduct of its day-to-day operational responsibilities, from performing Operating Work, engaging in business contacts and communications with SJCC or other coal suppliers or potential suppliers to the San Juan Project or in the administration of the CSA and related agreements.

20.4.1 The Participant which is a signatory to the CSA shall be entitled to have at least two (2) representatives present at any such negotiations or discussions. Remaining Participants not signatories to the CSA or its successors shall have the collective right to have two (2) representatives present at any such negotiations or discussions. The Remaining Participants may jointly or separately designate representatives, but in no case may the total number of representatives so designated by all of the Remaining Participants exceed two (2). Any dispute among the Remaining Participants regarding the naming of representatives shall be subject to resolution pursuant to Section 37 and shall not restrict the rights of any other representatives to engage in any ongoing negotiations or discussions. Representatives shall be designated in writing by the Participant which is a signatory to the CSA and Remaining Participants. If such representatives are not employees of a Remaining Participant, such fact shall be disclosed in writing to all Parties. Representatives shall agree in writing to: (i) avoid any conflict of

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interest that would be detrimental to the operation of the San Juan Project; and (ii) maintain all proprietary information obtained through such negotiations and discussions in confidence. The form of such confidentiality agreements shall be prepared by the Fuels Committee, and shall be subject to the approval of the Participant that is a signatory to the CSA, such approval not to be unreasonably withheld. Such confidentiality agreements shall be executed by a Remaining Participant’s Coordination Committee representative or, as appropriate, the person authorized by such Remaining Participant or Representative to execute such documents. Representatives may be changed by Remaining Participants by the giving of written notice to all other Parties.

20.4.2 Representatives shall make regular reports to, coordinate with, and obtain the recommendations of the Fuels Committee regarding the progress of and issues involved in such coal negotiations or discussions.

20.5 Any proposed action or determination regarding any amendment of the CSA, replacement of the CSA with a new agreement or any interim or other annual coal pricing agreement related to the CSA (or its successor) or any other action or determination of the Fuels Committee shall be submitted to the vote of the representatives of the Remaining Participants on the Fuels Committee. Any such action or determination shall require the affirmative vote as established in Section 18.4.3, in conjunction with Section 7.13.1.3, except that if a Remaining Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majority for actions or determinations

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specified in Section 18.4.3 shall be adjusted in proportion to the number of Remaining Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII.

20.5.1 If, upon such vote, the requisite votes are obtained, the Participant which is a signatory to the CSA then in effect or the Operating Agent, as applicable, shall proceed in accordance with the affirmative vote of the Fuels Committee without further action of any other San Juan Project committee.

20.5.2 If, upon such vote, the requisite votes are not obtained, the matter giving rise to the vote shall, not later than thirty (30) days after the negative vote of the Fuels Committee, be submitted to the Coordination Committee for its vote in accordance with Section 18.4.3. If the requisite majorities are obtained in the Coordination Committee vote, the Participant which is a signatory to the CSA then in effect or the Operating Agent, as applicable, shall proceed in accordance with the affirmative vote of the Coordination Committee.

20.5.3 If the requisite votes are not obtained in the Coordination Committee vote, then consistent with Section 18.7, the Participant which is a signatory to the CSA then in effect or the Operating Agent, as applicable, shall have the obligation and the responsibility, consistent with Prudent Utility Practice, to maintain a supply of coal to the San Juan Project.

20.6 The Fuels Committee shall keep written minutes and records of all meetings. Any action or determination made by the Fuels Committee shall be reduced to

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writing and shall become effective when signed by the representatives of the Parties representing a voting majority. Fuels Committee representatives may, by prior arrangement with the chairperson of the Fuels Committee, attend a meeting of the Fuels Committee by conference call or video. A Fuels Committee representative who is unable to attend a meeting of the Fuels Committee may vote in absentia by delivering to the chairperson of the Fuels Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

20.7 Nothing in this Section 20 is intended to affect the responsibilities of the Reclamation Oversight Committee or the Reclamation Trust Funds Operating Agent as set out in the Mine Reclamation Agreement; in particular, the Fuels Committee shall have no authority to vote as to matters related to amendments to provisions of the RSA or a new agreement for the performance of reclamation services for disturbance of the SJCC Site Area. To the extent of any conflict between this Section 20 and the Mine Reclamation Agreement, the provisions of the Mine Reclamation Agreement shall control.

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21.0 AUDITING COMMITTEE:

21.1 The Auditing Committee shall remain in existence during the term of this Agreement. The Auditing Committee shall have no authority to modify any of the provisions of this Agreement.

21.2 The Auditing Committee shall consist of one representative from each Party. Any of the Parties may designate an alternate or substitute to act as its representative on the Auditing Committee in the absence of the regular representative on the Auditing Committee or to act on specified occasions or with respect to specified matters. Each Party shall notify the other Parties promptly, in writing, of the designation of its representative and alternate representative on the Auditing Committee and of any subsequent changes in such designation.

21.3 The Auditing Committee shall have the following functions and responsibilities under this Agreement:

21.3.1 Review accounting, financial and internal control aspects of Operating Work and Capital Improvements, and implementation of procedures established pursuant to Section 20.3.8, and, not less than every two years, audit the records maintained by the Operating Agent in its performance of Operating Work, Capital Improvements and any other records maintained by the Operating Agent in support of its billings to the Parties.

21.3.2 Review and approve the format and content of the Operating Agent’s accounting records and reports for Operating Work and Capital Improvements.

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21.3.3 Certify to the Parties, for management purposes and for the use of the Parties only, that the Operating Agent’s results of operations and accounting methods and records, including any allocations for Operating Work and Capital Improvements, are in accordance with the Project Agreements and Accounting Practice.

21.3.4 Review and make recommendations to the Coordination Committee regarding a Party’s administrative and general expense allowance and other normal loadings when such Party acts as construction agent for Capital Improvements.

21.3.5 Review and approve the Operating Agent’s cost and expense allocations between (i) electric generation and related functions and (ii) unrelated functions.

21.3.6 Advise and make recommendations to the Coordination Committee and Operating Agent on matters involving auditing and financial transactions.

21.3.7 Develop procedures for proper accounting and financial liaison between Parties in connection with the Operating Work and Capital Improvements.

21.3.8 Perform such functions and responsibilities as may be assigned to it from time to time by the Coordination Committee or as otherwise provided in this Agreement.

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determinations which relate solely to a Unit or common property in which such Participant does not have a Participation Share except that if a Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majority for actions or determinations specified in Section 18.4.1 shall be adjusted in proportion to the number of Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII.

21.5 The Auditing Committee shall keep written minutes and records of all meetings, and any action or determination by the Auditing Committee shall be reduced to writing and shall become effective when signed by the representatives of the Parties entitled to vote thereon, representing a voting majority of the members of the Auditing Committee. Auditing Committee representatives may, by prior arrangement with the chairperson of the Auditing Committee, attend a meeting of the Auditing Committee by conference call or video conferencing. An Audit Committee representative who is unable to attend a meeting of the Audit Committee may vote in absentia by delivering to the chairperson of the Audit Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

21.6 In the event less than a requisite majority of the Auditing Committee is obtained, the matter shall be referred to the Coordination Committee for decision upon the request of any Party’s Auditing Committee representative.

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21.7 In the event the Auditing Committee fails to reach agreement on a matter which such committee is authorized to determine, approve or otherwise act upon after a reasonable opportunity to do so, then the Operating Agent shall be authorized and obligated to take such reasonable and prudent action, consistent with Prudent Utility Practice, as is necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree.

21.8 To the extent practicable, any audit of A&G expenses will be coordinated with audits of A&G expenses under any other San Juan Project-related agreements, including audits of Reclamation A&G Expenses.

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PART V

BUDGETS AND OPERATING EXPENSES

22.0 OPERATION AND MAINTENANCE EXPENSES:

22.1 The expenses for the operation and maintenance of the San Juan Project in the performance of Operating Work (which, for purposes of this Section 22, and as defined more particularly herein, are referred to as the “O&M Expenses”) shall be apportioned among the Parties, in accordance with the following percentages:

22.1.1 For Units 1 and 2 and for all equipment and facilities directly related to Units 1 and 2 only, in accordance with the following percentages:

22.1.1.1 PNM - 50 percent

22.1.1.2 TEP - 50 percent

22.1.1.3 M‑S‑R - 0 percent

22.1.1.4 Farmington - 0 percent

22.1.1.5 Tri-State - 0 percent

22.1.1.6 LAC - 0 percent

22.1.1.7 SCPPA - 0 percent

22.1.1.8 Anaheim - 0 percent

22.1.1.9 UAMPS - 0 percent

22.1.1.10 PNMR-D – 0 percent

22.1.2 For Unit 3 and all equipment and facilities directly related to Unit 3 only, in accordance with the following percentages:

22.1.2.1 PNM - 50 percent

22.1.2.2 TEP - 0 percent

22.1.2.3 M‑S‑R - 0 percent

22.1.2.4 Farmington - 0 percent

22.1.2.5 Tri-State - 8.2 percent

22.1.2.6 LAC - 0 percent

22.1.2.7 SCPPA - 41.8 percent

22.1.2.8 Anaheim - 0 percent

22.1.2.9 UAMPS - 0 percent

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22.1.2.10 PNMR-D – 0 percent

22.1.3 For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:

22.1.3.1 PNM - 38.457 percent

22.1.3.2 TEP - 0 percent

22.1.3.3 M‑S‑R - 28.8 percent

22.1.3.4 Farmington - 8.475 percent

22.1.3.5 Tri-State - 0 percent

22.1.3.6 LAC - 7.20 percent

22.1.3.7 SCPPA - 0 percent

22.1.3.8 Anaheim - 10.04 percent

22.1.3.9 UAMPS - 7.028 percent

22.1.3.10 PNMR-D – 0 percent

22.1.4 For equipment and facilities common to Units 1 and 2 only, in accordance with the following percentages:

22.1.4.1 PNM - 50 percent

22.1.4.2 TEP - 50 percent

22.1.4.3 M-S-R - 0 percent

22.1.4.4 Farmington - 0 percent

22.1.4.5 Tri-State - 0 percent

22.1.4.6 LAC - 0 percent

22.1.4.7 SCPPA - 0 percent

22.1.4.8 Anaheim - 0 percent

22.1.4.9 UAMPS - 0 percent

22.1.4.10 PNMR-D – 0 percent

22.1.5 For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:

22.1.5.1 PNM - 44.119 percent

22.1.5.2 TEP - 0 percent

22.1.5.3 M‑S‑R - 14.4 percent

22.1.5.4 Farmington - 4.249 percent

22.1.5.5 Tri-State - 4.1 percent

22.1.5.6 LAC - 3.612 percent

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22.1.5.7 SCPPA - 20.9 percent

22.1.5.8 Anaheim - 5.07 percent

22.1.5.9 UAMPS - 3.55 percent

22.1.5.10 PNMR-D – 0 percent

22.1.6 For the Switchyard Facilities except as otherwise provided in Section 15, in accordance with the following percentages:

22.1.6.1 PNM - 65 percent

22.1.6.2 TEP - 35 percent

22.1.6.3 M‑S‑R - 0 percent

22.1.6.4 Farmington - 0 percent

22.1.6.5 Tri-State - 0 percent

22.1.6.6 LAC - 0 percent

22.1.6.7 SCPPA - 0 percent

22.1.6.8 Anaheim - 0 percent

22.1.6.9 UAMPS - 0 percent

22.1.6.10 PNMR-D – 0 percent

22.1.7 Except as provided in Exhibit V(g), attached hereto and incorporated herein, for equipment and facilities common to all of the Units, and all San Juan Project expenses not identifiable by Unit and not otherwise listed above, in accordance with the following percentages:

22.1.7.1 PNM - 46.297 percent

22.1.7.2 TEP - 19.8 percent

22.1.7.3 M‑S‑R - 8.7 percent

22.1.7.4 Farmington - 2.559 percent

22.1.7.5 Tri-State - 2.49 percent

22.1.7.6 LAC - 2.175 percent

22.1.7.7 SCPPA - 12.71 percent

22.1.7.8 Anaheim - 3.10 percent

22.1.7.9 UAMPS - 2.169 percent

22.1.7.10 PNMR-D – 0 percent

22.1.8 In the event of a permanent shutdown of either of Unit 1 or Unit 2 prior to the Exit Date, the expenses incurred in connection with the shutdown

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(which may include removal, salvage, cleanup and protection service) shall be allocated as set forth in Section 22.1.1. In the event of a permanent shutdown of Unit 3 prior to the Exit Date, said expenses shall be allocated as set forth in Section 22.1.2. In the event of a permanent shutdown of Unit 4 prior to the Exit Date, said expenses shall be allocated as set forth in Section 22.1.3. Expenses which are attributable to equipment and facilities common to more than one Unit shall be apportioned in accordance with Section 22.1, as applicable. Expenses incurred under this Section 22.1.8 shall be minimized insofar as reasonably practicable, and any expenses paid by a Participant under this Section 22.1.8 that would otherwise qualify as costs of initial or interim Decommissioning Work under Sections 4.1 and 4.2 of the Decommissioning Agreement shall be credited against the Participants’ cost responsibilities under the Decommissioning Agreement.

22.1.9 Exhibit V, attached hereto and incorporated herein, is a partial list of equipment and facilities of the San Juan Project for use by the Engineering and Operating Committee as a guideline in determining the allocation of operation and maintenance costs among the Participants.

22.1.10 In areas where the allocation of costs of operation and maintenance of equipment and facilities among the Participants is not clearly defined by Sections 22.1.1 to 22.1.8, the Engineering and Operating Committee shall make a determination of such allocation of costs.

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22.1.11 The following shall apply in the event of a declaration of default against a Participant and a suspension of that Participant’s right to receive all or any part of its proportionate share of the Net Effective Generating Capacity, as provided for in Section 35.4.1: those non-defaulting Participant(s) having a Participation Share in each affected Unit, who are entitled to schedule and receive for their accounts proportionate shares of the Net Effective Generating Capacity of the defaulting Participant, shall bear proportionate shares of the defaulting Participant’s responsibility for expenses of the operation and maintenance of the San Juan Project, as provided in Section 35.5.

22.2 O&M Expenses chargeable to the following FERC Accounts shall be apportioned among the Participants in accordance with Sections 22.1.1, 22.1.2, 22.1.3, 22.1.4, 22.1.5 and 22.1.7, as applicable:

22.2.1 Power Production/Steam Power Generation: FERC Accounts 500, 502, 505, 506, 507, 509 and 510 through 514 (charged by on-site San Juan Project employees and operations-related departments located off-site); provided, however, that limestone costs (chemicals) chargeable to FERC Account 502 shall be apportioned among the Participants in accordance with Section 23.5.

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in accordance with Section 22.4. Such direct A&G charges must be supported by the Operating Agent and are subject to audit and approval by the Auditing Committee. If the Auditing Committee is unable to agree on the appropriateness of direct A&G charges, the Auditing Committee shall submit the entire matter to the Coordination Committee.

22.2.3 O&M Expenses chargeable to FERC Account 501 shall be apportioned among the Participants in accordance with Section 23.

22.2.4 The cost of the property insurance for the San Juan Project chargeable to FERC Account 924 and any uninsured loss or expense thereunder and the cost of general liability or workers’ compensation insurance for the San Juan Project chargeable to FERC Account 925 shall be apportioned among the Participants according to Section 22.1.

22.2.5 Costs or revenues chargeable to the following FERC Operating and Non-Operating Accounts: 411.8, 411.9, 412, 421 and 426.

22.3 Power Production Expense chargeable to FERC Account 500 (for employees of PNM’s fuels management department), Non San Juan Project Specific, shall be allocated among all of PNM’s fossil-fueled power plants, including the San Juan Project, based on the percentage of labor charged to each fossil-fueled power plant as a percentage of labor charged to all of PNM’s fossil-fueled power plants.

22.4 The O&M Expenses for the Switchyard Facilities chargeable to FERC Accounts 560 through 573 and FERC Account 935 shall be apportioned among the Participants in accordance with Section 22.1.6.

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22.5 The O&M Expenses for the portion of system control and load dispatching expenses (allocated between PNM and the San Juan Project based on the number of megawatts of San Juan Project capacity as a percentage of PNM’s total generating capacity) chargeable to FERC Accounts 556, 560 and 561 shall be apportioned among the Participants in accordance with Section 22.1.7.

22.6 Payroll loads for administrative and general expenses, payroll taxes, injuries and damages and pension and benefits, shall be added to the monthly billings in proportion to the dollars of direct labor billed and apportioned among the Participants in accordance with Sections 22 and 23. The current methodologies for calculating the A&G Ratio, Payroll Tax Ratio, Injuries and Damages Ratio and Pension and Benefits Ratio are set forth in Exhibit VI (Attachments A, B, C and D thereto), attached hereto and incorporated herein.

22.6.1 If any Participant believes that the method used in determining A&G Ratio, Payroll Tax Ratio, Injuries and Damages Ratio and Pension and Benefits Ratio, in accordance with Exhibit VI (Attachments A, B, C and D thereto), results in an unreasonable burden on such Participant(s), such Participant(s) may request that said method used in determining said ratios be submitted to the Auditing Committee for review. After any such request, the Auditing Committee shall review said method and shall endeavor to agree upon whether or not said unreasonable burden does actually exist. If, after such review, the Auditing Committee determines that the application of said method does result in an unreasonable burden on the Participant, the Auditing Committee shall determine and recommend a modified

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method to the Coordination Committee to eliminate such unreasonable burden. If, after such review, the Auditing Committee is unable to agree upon whether or not such unreasonable burden does exist or is unable to agree on a modified method for eliminating said unreasonable burden, the Auditing Committee shall submit the entire matter to the Coordination Committee.

22.6.2 The Coordination Committee shall review the recommendation of the Auditing Committee pursuant to Section 22.6.1. If, as a result of such review, the Coordination Committee agrees that such unreasonable burden does exist and that a modified method eliminates such unreasonable burden, the Coordination Committee shall adopt said modified method.

22.6.3 If the Auditing Committee has not submitted a recommended modified method and the Coordination Committee agrees that such unreasonable burden does exist, the Coordination Committee shall endeavor to agree on a modified method. If, after such review, the Coordination Committee is unable to agree that such unreasonable burden does exist or on a modified method which will eliminate such unreasonable burden, upon request of a Participant, either matter may be submitted to arbitration pursuant to Section 37.

22.6.4 Any modified method adopted by the Coordination Committee or determined through arbitration shall be retroactive for the length of the period of inequity up to a maximum period of three (3) years and shall become effective on the first day following such date of adoption.

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22.7 As soon as possible after the end of each calendar year, the Operating Agent shall calculate the actual ratios for: A&G, payroll tax, injuries and damages, and pension and benefits for such year in accordance with the methodologies described in Exhibit VI (Attachments A, B, C and D thereto). To the extent such expenses are more or less than those already paid by the Participants during said year, the Operating Agent shall bill or credit the Participants for the amount of such difference.

22.8 At the start of each calendar year, the Operating Agent shall calculate new ratios for: A&G, payroll tax, injuries and damages and pension and benefits. Such ratios shall be calculated in accordance with the methodologies described in Exhibit VI (Attachments A, B, C and D thereto). Such ratios may be adjusted to more nearly reflect the anticipated expenses of the current year because of tax legislation, labor contract negotiations or other factors not reflected in the prior year’s costs.

22.9 The Operating Agent shall bill to the requesting Party(ies) the costs and expenses, including A&G expenses, incurred by the Operating Agent (including, but not limited to, fees of outside legal counsel or consultants, time of in-house legal counsel and other employees and agents of the Operating Agent) in performing tasks requested by a Party in relation to (i) the offering or sale of bonds or other type of security by a Party in connection with the acquisition or ownership of an interest in the San Juan Project; and (ii) the attempted or contemplated sale by a Party of any portion of its ownership interest in the San Juan Project. The Operating Agent shall establish and maintain appropriate accounting procedures to identify such costs and expenses incurred by the Operating Agent.

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23.0 FUEL COSTS:

23.0(a) For (i) allocation of payment obligations for coal supply, reclamation and CCR disposal under the UG-CSA, the CCBDA, the UG-CSA Termination Agreement and the CCBDA Termination Agreement; and (ii) allocation of any fuel-related payments (other than for coal) accrued through December 31, 2017 and chargeable to FERC Account 501, including limestone, fuel oil, CCR disposal, fuel handling or start-up or auxiliary power and energy, Sections 23.1 through 23.13 shall apply.

23.0(b) For payment obligations arising under the CSA and the CCRDA, Sections 23.14 through 23.18 shall apply.

23.0(c) All costs and expenses incurred by the Reclamation Trust Funds Operating Agent under the Mine Reclamation Agreement before December 31, 2017 shall be billed to the Participants as Operating Work of the Operating Agent.

23.1 The quantity of coal delivered to the San Juan Project shall be determined by the belt scales, in accordance with the CSA.

23.2 The Operating Agent shall maintain the Project Coal Inventory wherein ownership shall be apportioned among the Participants in the percentages shown in Section 6.3. Coal inventory shall be accounted for in FERC Account 151.

23.3 All Participants acknowledge and recognize the terms and conditions of the Underground Coal Sales Agreement which was entered into by PNM and TEP on behalf of the Participants. Exhibit VII, attached hereto and incorporated herein, contains example

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“Interim Invoices”, “UG-CSA Invoices”, and “UPS Invoices” prepared and defined pursuant to Section 8 of the Underground Coal Sales Agreement.

23.4 Monthly costs of the Project Coal Inventory and fuel expense shall be apportioned among and paid for by the Participants on the following basis:

23.4.1 UG-CSA Invoicing Allocations

In the event that UG-CSA Invoices are rendered and payable pursuant to Section 8.7 (A) of the Underground Coal Sales Agreement, amounts due thereunder shall be allocated and paid for by the Participants as Fixed Fuel Expense and Variable Fuel Expense as described in: Exhibit IX, Fixed Fuel Expense; and Exhibit X, Variable Fuel Expense and as provided below:

23.4.1.1 Costs that are classified as Fixed Fuel Expense shall be charged to FERC Account 501, or to such FERC Account number as may be applicable in the future if fuel deliveries terminate, and shall be apportioned among and paid for by the Participants in accordance with Common Participation Share.

23.4.1.2 Costs that are classified as Variable Fuel Expense shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Participants on the basis of Common Participation Share. Monthly cost for coal withdrawn from Project Coal Inventory (equivalent to total monthly Participant Coal Consumption) shall be credited to FERC Account 151 and charged to FERC Account 501 on an

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average price basis as determined by dividing the total number of tons of coal in Project Coal Inventory at the beginning of the month, plus the coal delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per ton so derived by the number of tons withdrawn. The cost for coal withdrawn charged to FERC Account 501 shall be apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units. The cost for coal withdrawn thusly credited to FERC Account 151 shall be apportioned among the Participants on the basis of Common Participation Share.

23.4.1.3 Any other Total Monthly Coal Cost not currently classified in Exhibits IX or X as Fixed Fuel Expense or Variable Fuel Expense shall be deemed to be Fixed Expense until reclassified by the Coordination Committee.

23.4.2 Interim Invoicing Allocations

In the event that Interim Invoices are rendered and payable pursuant to Section 8.7 (B) of the Underground Coal Sales Agreement, such costs shall be allocated and invoiced to the Participants as described below.

23.4.2.1 The Base Price (“Base Price”) band shall be based on the Minimum Annual Tons. The annual allocation of the coal tonnage

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in the Base Price band shall be made among the Participants on the basis of Common Participation Share. The monthly allocation of the coal tonnage in the Base Price band shall be made among the Participants on the basis of each Participant’s share of Monthly Minimum Tons. The cost of the monthly Base Price band will be allocated among and paid for by the Participants by multiplying each Participant’s share of Monthly Minimum Tons by the Base Price.

23.4.2.2 The Incremental Price (“Incremental Price”) band(s) shall be based on (an) annualized band(s) of tons of coal delivered in excess of Minimum Annual Tons. The cost of the monthly Incremental Price band(s) will be allocated among and paid for by the Participants by multiplying each Participant’s consumption of Incremental Price band coal(s) by the Incremental Price for such band(s). Participants shall only be eligible for allocation of Incremental Price band coal pricing if their monthly Participant Coal Consumption exceeds their share of Monthly Minimum Tons.

23.4.2.3 At the end of each year, the Operating Agent shall reconcile the sum of each Participant’s monthly Interim Invoice-related payments to a properly allocable share of Base Price band tons, Incremental Price band or bands tons, and cost associated with any change in Project Coal Inventory and invoice or refund any such reconciliation

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amounts to each Participant. This reconciliation will be exclusive of any year-end true up required pursuant to Section 23.4.2.6.

23.4.2.4 In the year-end reconciliation process of Section 23.4.2.3, any amount credited by SJCC for tons invoiced but not delivered shall be credited to FERC Account 501 and apportioned to the Participants on the basis of the percentage that each Participant’s annual Incremental Price Band(s) consumption bears to the total annual Incremental Price Band(s) consumption for all Units. Any net consumption of Project Coal Inventory tons shall be charged to FERC Account 501 and apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s annual Incremental Price Band(s) consumption bears to the total annual Incremental Price Band(s) consumption for all Units. The price for such tons shall be determined by dividing the total recorded cost in FERC Account 151 by the total number of tons of coal in Project Coal Inventory, both as recorded on January 1 of said year. The total amount of any such payment for consumed Project Coal Inventory tons shall subsequently be credited to FERC Account 151 and apportioned to the Participants based on Common Participation Share.

In the year-end reconciliation process of Section 23.4.2.3, the costs of any net addition to Project Coal Inventory tons, as invoiced by SJCC, shall be

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charged to FERC Account 151 and apportioned to and paid for by the Participants based on Common Participation Share.

23.4.2.5 If, at the end of any year, the Operating Agent has collected amounts in excess of those due S JCC pursuant to Section 8.7(B) of the Underground Coal Sales Agreement, but not including any year-end true up required pursuant to Section 23.4.2.6, such over-collection shall be refunded to the Participants. The refund to each Participant shall be an amount equal to the total amount of the over-collection multiplied by the tons each Participant’s Coal Consumption was less than its total annual Monthly Minimum Tons divided by the total amount by which all such Participants’ Coal Consumption was less than their shares of Minimum Annual Tons.

23.4.2.6 The Interim Invoices shall be annually reconciled to invoices prepared pursuant to Section 8.7(A) of the Underground Coal Sales Agreement. Any adjustment required by this reconciliation, in accordance with Section 8.7(B) of the Underground Coal Sales Agreement, will be passed through to the Participants as correcting invoices and will be apportioned among and paid for by, or credited to, the Participants on the basis of Common Participation Share.

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23.4.2.7 Monthly UPS payments shall be apportioned among and paid for by the Participants on the basis of Common Participation Share

23.4.2.8 Any other component of Total Monthly Coal Cost which is not classified as Base Price or Incremental Price shall be apportioned among and paid for by the Participants on the basis of Common Participation Share unless otherwise annually approved by the Fuels Committee.

23.4.2.9 If during any year, payable Interim Invoices cease to be rendered by SJCC pursuant to Section 8.7(B) of the Underground Coal Sales Agreement, the Participants acknowledge and recognize that Interim Invoicing cannot be in effect for a partial year, and that all allocations of Total Monthly Coal Costs for the year shall then be made pursuant to Section 23.4.1. Amounts previously allocated to the Participants pursuant to Section 23.4.2 in the affected year shall be reallocated pursuant to the provisions of Section 23.4.1.

23.4.2.10 The Fuels Committee may terminate allocation of costs to the Participants pursuant to Section 23.4.2 despite the continued receipt of payable Interim Invoices from SJCC, if the Fuels Committee determines that coal cost allocation pursuant to Section 23.4.1 better serves the interests of the San Juan Project. Such termination may only be made

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upon action of the Fuels Committee pursuant to Section 20.5. In the event of such termination, costs shall continue to be apportioned to and paid for by the Participants pursuant to Section 23.4.2. However, for information purposes, the Operating Agent shall also provide cost allocations to the Participants pursuant to Section 23.4.1. At the end of such year, the amounts paid by the Participants shall be reconciled to those amounts allocated pursuant to Section 23.4.1 for each month of the affected year (Section 23.4.1 allocations being determinative) and the Operating Agent shall invoice or refund any such reconciliation amounts to each Participant.

23.5 Limestone costs (chemicals) chargeable to FERC Account 502 shall be apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units.

23.6 All other fuel-related expenses which are chargeable to FERC Account 501 shall be apportioned among and paid for by the Participants on the following basis:

23.6.1 Variable fuel-related expenses (including, but not limited to ash and gypsum disposal) on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units.

23.6.2 Fixed fuel-related expenses (including, but not limited to fuel handling) on the basis of Common Participation Share.

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23.6.3 Fuel oil purchased for use at the San Juan Project is first delivered into one of two storage tanks. Tank 1 and 2 storage tank feeds Units 1 and 2 and Tank 3 and 4 storage tank feeds Units 3 and 4. When oil is withdrawn from a storage tank for consumption, it is metered by Unit. Costs for fuel oil usage shall be separately accounted for by these two storage tanks as follows:

23.6.3.1 Costs for fuel oil purchases to Tank 1 and 2 shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Units 1 and 2 Participants on the basis of Section 6.2.4. Monthly cost for fuel oil withdrawn from Tank 1 and 2 shall be credited to FERC Account 151 and charged to FERC Account 501 on an average price basis as determined by dividing the total number of gallons of fuel oil in Tank 1 and 2 at the beginning of the month, plus the fuel oil delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per gallon so derived by the number of gallons withdrawn from Tank 1 and 2. The cost for fuel oil withdrawn from Tank 1 and 2 charged to FERC Account 501 shall be apportioned among and paid for by the Units 1 and 2 Participants first on the basis of the individual Unit metered consumption and then on the basis of Section 6.2.1. The cost for fuel oil withdrawn from Tank 1 and 2 thusly credited to FERC Account 151 shall be apportioned among the Units 1 and 2 Participants on the basis of Section 6.2.4.

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23.6.3.2 Costs for fuel oil purchases to Tank 3 and 4 shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Units 3 and 4 Participants on the basis of Section 6.2.5. Monthly cost for fuel oil withdrawn from Tank 3 and 4 shall be credited to FERC Account 151 and charged to FERC Account 501 on an average price basis as determined by dividing the total number of gallons of fuel oil in Tank 3 and 4 at the beginning of the month, plus the fuel oil delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per gallon so derived by the number of gallons withdrawn from Tank 3 and 4. The cost for fuel oil withdrawn from Tank 3 and 4 charged to FERC Account 501 shall be apportioned among and paid for by the Units 3 and 4 Participants first on the basis of the individual Unit metered consumption and then on the basis of Section 6.2.2 or Section 6.2.3, as applicable. The cost for fuel oil withdrawn from Tank 3 and 4 thusly credited to FERC Account 151 shall be apportioned among the Units 3 and 4 Participants on the basis of Section 6.2.5.

23.7 The Operating Agent shall provide the Participants a monthly written report on the following items related to coal deliveries at the San Juan Project:

23.7.1 Minimum Annual Tons for the year.

23.7.2 Minimum Annual Tons allocated among the Participants.

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23.7.3 Total actual coal deliveries by SJCC to the San Juan Project for each month and for the year to date.

23.7.4 Total actual coal deliveries to the San Juan Project for each month and for the year to date, allocated to the Participants.

23.7.5 Total cost and tonnage of inventory allocated to the Participants.

23.7.6 Fixed Fuel Expense and Variable Fuel Expense totals as allocated to each Participant for each month and for the year to date if UG-CSA Invoicing is, or will be, required for said year pursuant to Section 23.4.1.

23.8 The Operating Agent shall work diligently with SJCC under the terms of the CSA to manage Project Coal Inventory so as to maintain the Emergency Coal Storage Pile at target levels pursuant to Section 20.3.6 and to maintain appropriate working levels of Project Coal Inventory to facilitate San Juan Project Operations.

23.9 In the event that SJCC defaults in its obligations under the CSAor otherwise fails to maintain deliveries of coal, the Operating Agent may assume or make such arrangements for the assumption of such of SJCC’s operations as permitted by the CSA or may procure, subject to the CSA, an alternate coal supply. Costs associated with such assumed coal operations or the procurement and supply of alternate coal shall be deemed a part of Total Monthly Coal Cost and, with the costs and expenses of fuel and emission residuals (gypsum) and ash disposal, shall be apportioned between and paid for by the Participants in accordance with: (i) Section 23.4.1 with regard to coal costs; and (ii) Section 23.6.1 with regard to fuel-related costs.

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23.10 The monthly costs of fuel allocated among the Participants in accordance with this Section 23 shall be estimated by the Operating Agent as soon as practicable after the end of each month and a preliminary bill shall be presented and paid in the manner set forth in Section 30.3.3. Adjustments and corrections to the estimated preliminary bill shall be made in the next succeeding month or on the earliest possible billing thereafter.

23.11 In the event of a catastrophic occurrence which results in a sustained outage of a Unit and a determination that an “Uncontrollable Force” exists under the CSA, then in such event, FERC Account 151 will be allocated to the operable and non-operable Units. The portion of FERC Account 151 allocated to the non-operable Unit(s) shall remain frozen until such time as such Unit(s) is restored to operable condition. New costs of coal chargeable to FERC Account 151 will be apportioned among the Participants on the basis of the Participants’ Participation Shares in the generating capacity of the operable Units. At such time as a damaged Unit is restored to operable condition, the frozen portion of Account 151 will be merged into the operable unit(s) portion of Account 151 and to the extent that a Participant is adversely impacted by an incremental increase in the average unit cost of coal an allocation of such incremental cost will be made and the net difference paid by the Participant having a credit balance.

23.12 The accounting practices and billing and accounting principles as stated in this Section 23 are applicable at the present time. If, however, at a later time these practices or principles are proven to be inadequate or other practices or principles later prove to be more equitable in the opinion of the Auditing Committee, the Coordination Committee,

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upon the recommendation of the Auditing Committee, may authorize changes and revisions to such practices and principles.

23.13 Any other fuel-related costs not currently classified in this Section 23 shall be apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units until classified by the Coordination Committee. 23.14 Notwithstanding the provisions of Sections 23.1 through 23.13, beginning on January 1, 2016, PNM will supply coal to (i) the Exiting Participants under the provisions of Sections 23.15 through 23.17; and (ii) the Remaining Participants under the provisions of Section 23.18. PNM will have all cost obligations under the CSA for coal supplied to the Exiting Participants and PNM will have all rights to the Exiting Participants’ inventory relinquished to PNM under Section 23.15.

23.15 The Exiting Participants will relinquish to PNM their Common Participation Shares of Shared Coal Inventory that exist as of January 1, 2016, at the following values: $16.88/ton for coal tons stockpiled on SJCC’s property and $22.69/ton for coal tons stockpiled on the SJGS plant site. The total sum paid by PNM for Common Participation Shares of Shared Coal Inventory will be allocated as follows:

23.15.1 M-S-R 32.22%

23.15.2 Anaheim 11.48%

23.15.3 SCPPA 47.08%

23.15.4 Tri-State 9.22%

23.16 From January 1, 2016 through the Exit Date, the Exiting Participants will receive coal monthly to meet their Participant Coal Consumption from PNM at a cost of

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$50/ton in 2016 and 2017. This $50/ton covers all payment obligations for coal supplied to the Exiting Participants that might otherwise be due under (i) the Restructuring Agreement; (ii) the CSA, including Legacy Costs, taxes and royalties; and (iii) gross receipts taxes under the Refined Coal Supply Agreement or otherwise. This $50/ton does not include payments for reclamation costs under the RSA or disposal costs under the CCRDA.

23.17 Exiting Participants will not have any take-or-pay or minimum purchase obligations under the CSA; provided, however, the Exiting Participants must comply with the following dispatch requirements. The Exiting Participants will dispatch their respective shares of the Units to no less than their Minimum Annual Generation. The Exiting Participants will be billed monthly based on their Participant Coal Consumption. At the end of each of 2016 and 2017, any Exiting Participant that has not met its Minimum Annual Tonnage Purchase Obligation will be billed at $50/ton for the difference between its actual Participant Coal Consumption and its Minimum Annual Tonnage Purchase Obligation; provided, in the event that at any time during 2016 or 2017 PNM is unable to supply coal to the Exiting Participants as provided in Section 23.16, then the Minimum Annual Tonnage Purchase Obligation will be proportionately reduced to account for any such period of time in which PNM is unable to supply coal.

23.18 For purposes of the calculations in this Section 23.18, PNM’s Common Participation Share will include the Exiting Participants’ Common Participation Share, and PNM’s Participant Coal Consumption will include the Exiting Participants’

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Participant Coal Consumption. SJCC will invoice PNM monthly as provided under the CSA. PNM will invoice each Remaining Participant monthly by Coal Tonnage Component and such Coal Tonnage Component will be paid for as follows:

23.18.1 Pre-existing Stockpile Coal tons as invoiced by SJCC will be allocated by a Remaining Participant’s Common Participation Share as of the Effective Date and will be paid for by each Remaining Participant at the price per ton charged by SJCC in its monthly invoicing to PNM.

23.18.2 Each year, PNM will develop a monthly Tier 1 Tonnage Allocation schedule with SJCC in the annual operating plan process as provided for in Section 7.2 of the CSA. With input from the Remaining Participants, PNM will develop a monthly allocation by Remaining Participant of such Tier 1 Tons (such individual allocation, its “Tier 1 Tonnage Allocation”). Such monthly Tier 1 Tonnage Allocation will be paid for by Remaining Participants whether or not their Participant Coal Consumption exceeded their Tier 1 Tonnage Allocation in the month. Monthly, for each Remaining Participant, its Tier 1 Tonnage Allocation, net of its invoiced Pre-existing Stockpile Coal for such month will be paid for at the then existing price for Tier 1 Tons under the CSA. In each of 2016 and 2017, five million six hundred thousand (5,600,000) tons will be allocated by Remaining Participant Share, and then PNM will be allocated an additional one hundred fifty thousand (150,000) tons in each of those years. In each of 2018 and 2019, two million eight hundred thousand (2,800,000) tons will be allocated by

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Remaining Participant Share. In each of 2020 and 2021, two million eight hundred thousand (2,800,000) tons will be allocated by Remaining Participant Share, and then PNM’s allocation will be reduced by one hundred fifty thousand (150,000) tons in each of those years. In 2022, one million four hundred thousand (1,400,000) tons will be allocated by Remaining Participant Share.

23.18.3 To the extent that a Remaining Participant’s Participant Coal Consumption in a month exceeds its Tier 1 Tonnage Allocation for such month, PNM will invoice such Remaining Participant such excess as Tier 2 Tons to be paid for at the then existing price for Tier 2 Tons under the CSA.

23.18.4 Legacy Costs as invoiced monthly by SJCC will be allocated using a Remaining Participant’s Common Participation Share for that year.

23.18.5 Cost for SJCC’s reclamation bond premium invoiced through the CSA will be allocated using a Remaining Participant’s Common Participation Share for that year.

23.18.6 Weight-based taxes will be applied to the tonnages as invoiced by PNM to each Remaining Participant at the then-existing rates applicable to SJCC invoices.

23.18.7 Revenue-based taxes and royalties will be applied to the tonnages and total coal costs as invoiced by PNM to each Remaining Participant at the then-existing rates applicable to SJCC invoices.

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23.18.8 In the event of an SJCC environmental force majeure, then Available Pre-existing Stockpile Tons will be allocated in the same manner as Pre-existing Stockpile Coal tons, and Force Majeure Tons will be allocated in the same manner as Tier 1 Tons unless otherwise approved by the Remaining Participants in the Fuels Committee. Such calculations will be on an annual basis.

23.18.9 Any other costs billed by SJCC under the CSA and not specifically addressed in this Section 23.18 will be apportioned among and paid for by the Remaining Participants on the basis of the Remaining Participant’s Common Participation Share for that year unless otherwise annually approved by the Remaining Participants in the Fuels Committee.

23.18.10 Annual Year-End Reconciliation Process.

23.18.10.1 At the end of each year, the Operating Agent will reconcile the sum of each Remaining Participant’s monthly CSA-related payments to a properly allocable share of annual Tier 1 Tons, Tier 2 Tons, Pre-existing Stockpile Coal tons, and cost associated with any change in Project Coal Inventory and invoice or refund any such reconciliation amounts to each Remaining Participant.

23.18.10.2 Any net consumption of Project Coal Inventory tons will be charged to FERC Account 501 and apportioned among and paid for by the Remaining Participants on the basis of the percentage that each Remaining Participant’s annual Tier 2 Tons after the reconciliation

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process bears to the total annual Tier 2 Tons consumption after the reconciliation process for all Units. The price for such tons will be determined by dividing the total recorded cost in FERC Account 151 by the total number of tons of coal in Project Coal Inventory, both as recorded on January 1 of said year. The total amount of any such payment for consumed Project Coal Inventory tons will subsequently be credited to FERC Account 151 and apportioned to the Remaining Participants based on the Remaining Participant’s Common Participation Share for that year.

23.18.10.3 The costs of any net addition to Project Coal Inventory tons, as invoiced by SJCC, will be charged to FERC Account 151 and apportioned to and paid for by the Remaining Participants based on the Remaining Participant’s Common Participation Share for that year.

23.18.10.4 If, at the end of any year, the Operating Agent has collected amounts in excess of those due SJCC under the CSA, such over-collection will be refunded to the Remaining Participants. The refund to each Remaining Participant will be an amount equal to the total amount of the over-collection multiplied by the tons each Remaining Participant’s Coal Consumption was less than its total annual Tier 1 Tonnage Allocation divided by the total amount by which all such Remaining Participants’ Coal Consumption was less than their Tier 1 Tonnage Allocation.

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23.19 The cost of evaluating a long-term fuel supply for the San Juan Project, approved pursuant to a resolution of the Coordination Committee of May 23, 2014, shall be shared among the Remaining Participants in accordance with the following percentages:

23.19.1 PNM - 62.708 percent

23.19.2 TEP - 19.8 percent

23.19.3 Farmington - 3.679 percent

23.19.4 LAC - 3.123 percent

23.19.5 UAMPS - 3.017 percent

23.19.6 PNMR-D – 7.673 percent

To the extent that the cost of evaluating a long-term fuel supply for the San Juan Project has been invoiced and paid at a different percentage allocation than that set forth immediately above, the Remaining Participants agree to a true-up of the over- or under- payment to these percentages as of the Effective Date.

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24.0 ANNUAL BUDGETS:

24.1 Not less than ninety (90) days prior to the beginning of each calendar year, the Operating Agent shall prepare and submit to the Engineering and Operating Committee for its review and approval the proposed capital budget, manpower budget and a budget for the performance of Operating Work for such calendar year.

24.2 The Engineering and Operating Committee shall approve the budgets described in Section 24.1 in final form not less than thirty (30) days prior to their effective date. In the event that any such budget is not so approved, the Operating Agent will nevertheless continue to perform Operating Work in a manner consistent with Prudent Utility Practice until such time as a budget has been approved.

24.3 Any information required from the Participants by the Operating Agent in preparing such proposed budgets will be supplied by the Participants, if possible, within thirty (30) days following a request by the Operating Agent.

24.4 The Engineering and Operating Committee may at any time during the year approve revisions to the approved capital expenditures budget, manpower budget and a budget for the performance of Operating Work.

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25.0 PAYMENT OF TAXES:

25.1 The Participants shall use their best efforts to have any taxing authority imposing any taxes or assessments on the San Juan Project, assess and levy such taxes or assessments directly against each Participant in accordance with its respective Participation Share in the property taxed.

25.2 All taxes or assessments levied against each Participant’s ownership interest in the San Juan Project, excepting those taxes or assessments levied against an individual Participant on behalf of other Participants, shall be the sole responsibility of the Participant upon whom said taxes and assessments are levied.

25.3 If any property taxes and other taxes and assessments are levied and assessed in a manner other than specified in Section 25.1, it shall be the responsibility of the Coordination Committee to establish equitable standard practices and procedures for the apportionment among the Participants of such taxes and assessments and the payment thereof.

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26.0 MATERIALS AND SUPPLIES:

26.1 The Operating Agent from time to time may increase or reduce the inventory of Materials and Supplies by changing the maximum or the minimum quantities to be maintained in inventory in accordance with the procedures established by the Engineering and Operating Committee.

26.2 The Operating Agent shall prepare a list of the items for inclusion in Materials and Supplies for the operation and maintenance of each Unit. The list shall include the estimated cost of each individual item of such Materials and Supplies and specify the maximum and minimum quantity of each such individual item to be maintained in inventory. The list shall be submitted to the Engineering and Operating Committee by the Operating Agent for review and approval.

26.3 The Operating Agent shall purchase and take control of Materials and Supplies for inventory, so that the total inventory of Materials and Supplies on hand remains in accordance with the policies established by the Engineering and Operating Committee.

26.4 Materials and Supplies withdrawn from inventory and used in the operation and maintenance of the San Juan Project shall be accounted for as a component of operation and maintenance expense and allocated among the Participants in accordance with Section 22.

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26.5 Materials and Supplies withdrawn from inventory and used in connection with Capital Improvements shall be accounted for as a capital expenditure and allocated among the Participants in accordance with Section 7.

26.6 Materials and Supplies removed from service shall be returned to inventory if reusable, or if junk or obsolete, shall be disposed of by the Operating Agent under the best available terms. The proceeds, if any, received shall be credited or distributed to the Participants in the same proportion as their Participation Shares therein.

26.7 A separate Materials and Supplies account and undistributed stores expense account will be established by the Operating Agent in accordance with FERC Accounts. Such charges and credits so allocated to Materials and Supplies shall be allocated to the Parties as a component of operation and maintenance expense in accordance with Section 22, or as a Capital Improvement in accordance with Section 7, as the case may be.

26.8 The inventory value of any item withdrawn from or returned to Materials and Supplies shall be the average cost of like items in inventory.

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27.0 EMERGENCY SPARE PARTS:

27.1 The Operating Agent shall prepare a list of the Emergency Spare Parts for each Unit and common facilities. Such list shall include the estimated costs for each individual item of such Emergency Spare Parts and shall specify the quantity of each such individual item to be maintained in inventory. Such list shall be submitted to the Engineering and Operating Committee by the Operating Agent for review and approval.

27.2 The Operating Agent shall purchase Emergency Spare Parts from time to time as replacements for those withdrawn from inventory in accordance with the policies established by the Engineering and Operating Committee.

27.3 Emergency Spare Parts shall be owned by and the costs thereof shall be allocated between the Participants in accordance with their respective Participation Shares.

27.4 The Operating Agent shall notify the Participants promptly after Emergency Spare Parts are withdrawn from inventory and shall also notify the Participants of the value of such parts so withdrawn and of the accounting treatment with respect thereto.

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PART VI

OPERATING AGENT

28.0 OPERATION AND MAINTENANCE:

28.1 PNM is the Operating Agent, unless replaced in accordance with Section 33.

28.2 All Parties hereby appoint PNM as their agent, and PNM agrees to undertake, as the agent of the Parties and as principal on its own behalf, the responsibility for the performance of Operating Work in accordance with this Agreement.

28.3 Subject to the provisions, conditions, limitations and restrictions of this Agreement, the Operating Agent shall:

28.3.1 Perform the Operating Work in accordance with the Project Agreements and Prudent Utility Practice.

28.3.2 Contract for, furnish or obtain the services and studies necessary for performance of Operating Work.

28.3.3 Arrange for the placement and maintenance of Operating Insurance.

28.3.4 Execute all contracts in the name of the Operating Agent, acting as principal on its own behalf and as agent for the Parties, in connection with the performance of Operating Work.

28.3.5 Furnish and train the necessary personnel for performance of Operating Work.

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28.3.6 Have the coal replaced which has been removed from the Emergency Coal Storage Pile at the earliest practical time following resumption of normal coal deliveries.

28.3.7 Enforce and comply with all contracts entered into for the performance of Operating Work.

28.3.8 Comply with any and all laws and regulations applicable to the performance of Operating Work.

28.3.9 Maintain the Operating Account and expend the Operating Funds only in accordance with this Agreement.

28.3.10 Keep and maintain records of monies expended and received, obligations incurred, credits accrued and contracts entered into in the performance of this Agreement, and make such records available for inspection by the Parties at reasonable times and places.

28.3.11 Not suffer any liens to remain in effect unsatisfied against the San Juan Project (other than the liens permitted under Section 10.1, for taxes or assessments not yet delinquent, for labor and material not yet delinquent or undetermined charges or liens incidental to the performance of Operating Work); provided, that the Operating Agent shall not be required to pay or discharge any such lien as long as a proceeding shall be pending in which the lawfulness or validity of such lien shall be contested in good faith and which shall operate during

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the pendency thereof to prevent the collection or enforcement of such lien so contested.

28.3.12 Recommend minimum notification times and lead times for changing scheduled Energy required for the Participants to the Engineering and Operating Committee for its approval.

28.3.13 Act as operating representative or agent in connection with the administration and enforcement of the CSA, the CCRDA and, through December 31, 2017, the RSA.

28.3.14 Recommend programs to the Engineering and Operating Committee to make environmental studies and, upon approval of the Engineering and Operating Committee, supervise the performance of such programs.

28.3.15 Provide the Engineering and Operating Committee with all written statistical and administrative reports, written budgets, information and other records relating to Operating Work which may be necessary to permit such committee to perform its responsibilities under this Agreement.

28.3.16 Provide the Fuels Committee with all written reports, written budgets, information and other records relating to Operating Work which may be necessary to permit such committee to perform its responsibilities under this Agreement.

28.3.17 Provide the Auditing Committee with all accounting records, information, reports and other records relating to Operating Work, which may be

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necessary to permit such committee to perform its responsibilities under this Agreement.

28.3.18 Perform Operating Work so as to comply with the Water Contract(s) and make such tests and measurements and keep such records as are required by applicable agreements, regulations and statutes.

28.3.19 Keep the Parties fully and promptly advised of material changes in conditions or other material developments affecting the performance of Operating Work and furnish the Parties with copies of any notices given or received pursuant to the Project Agreements.

28.3.20 Present claims to any insurer for losses and damages covered by valid and collectible Operating Insurance procured by the Operating Agent directly from the insurer. Investigate, adjust, settle, decline and defend claims against the Parties arising out of the performance of Operating Work when said claims or portions thereof are not covered by valid and collectible Operating Insurance; provided that the Operating Agent shall obtain the agreement of the Parties, acting through the Coordination Committee, prior to disposing of any claims or combination of claims arising out of the same occurrence which exceeds one hundred thousand dollars ($100,000).

28.3.21 Assist, as requested, other Parties and their insurers in the investigation, adjustment and settlement of any loss or claim arising out of Operating Work for which payment may be made on account of valid and

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collectible additional insurance applicable thereto procured by any such Party; provided, that the Operating Agent may agree (by separate agreement) that a Party procuring any policy or policies of additional insurance shall have the authority and the responsibility to (i) present, investigate, adjust, settle, decline and defend claims or potential claims covered by said policies in favor of the Parties and against any one or more of said insurers; and (ii) present, investigate, adjust, settle, decline and defend claims against the Parties arising out of the performance of Operating Work when said claims or portions thereof are not covered by said policies; and provided further, that such Party shall obtain the agreement of the Parties, acting through the Coordination Committee, prior to the settlement of any claim or combination of claims arising out of the same occurrence which exceeds one hundred thousand dollars ($100,000).

28.3.22 Notwithstanding anything in Section 28.3.20 and 28.3.21 to the contrary, any Party may at any time, at its own expense, employ its own counsel to assist in investigating, adjusting, settling, declining and defending claims of the types referred to in Sections 28.3.20 and 28.3.21 and the Operating Agent and its employees and counsel shall cooperate fully with such counsel and permit such counsel to participate fully in all of the foregoing activities.

28.3.23 Keep the Parties fully and promptly informed of any known default under the Project Agreements.

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28.3.24 Determine switching and clearance procedures to be followed by the Participants at the San Juan Project.

28.3.25 Determine Available Operating Capacity from time to time and make recommendations to the Engineering and Operating Committee regarding items referenced in Section 19.3.1.9.

28.3.26 Upon the request of a Party, provide such Party, in reasonable quantity without direct charge therefor, a copy or copies of any report, record, list, budget, manual, accounting or billing summary, classification of accounts, or other documents or revisions of any of the foregoing items, all as prepared in accordance with this Agreement.

28.3.27 In the event of the failure of the Participant which is a signatory to the CSA then in effect to reach agreement on a matter described in Sections 18.7 and 20.5.3, maintain a supply of coal to the San Juan Project, consistent with Prudent Utility Practice.

28.3.28 Manage the activities of the “designated representative” pursuant to the DR Agreement.

28.3.29 Perform all of the duties and obligations set out in this Agreement as duties and obligations of the Operating Agent.

28.3.30 Through December 31, 2017, perform the duties and obligations of the Reclamation Trust Funds Operating Agent under the Mine Reclamation Agreement.

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28.3.31 Cooperate in the performance of the baseline environmental study and related environmental audits, as provided for in the Restructuring Agreement.

28.4 The Parties shall lend and be properly reimbursed for all necessary and available assistance as may be requested by the Operating Agent in the performance of Operating Work.

28.5 The Operating Agent shall be the agent of the Parties and shall exercise only such authority as is conferred upon it by this Agreement. The Operating Agent shall not receive any fee or profit hereunder, unless otherwise agreed unanimously by the Parties.

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29.0 OPERATING EMERGENCY:

29.1 In the event of an Operating Emergency, the Operating Agent shall take any and all steps reasonably necessary and required to terminate the Operating Emergency, subject to the provisions of this Section 29.

29.2 As soon as practicable after the commencement of an Operating Emergency, the Operating Agent shall advise the Participants of the occurrence of the Operating Emergency, its nature and the steps taken or to be taken to terminate the Operating Emergency, including a preliminary estimate of the expenditures required to terminate the Operating Emergency.

29.3 In the event that the estimated cost to cure an Operating Emergency with respect to any Unit or to any equipment and facilities common to any of the Units does not exceed two hundred and fifty thousand dollars ($250,000), the Operating Agent shall have the authority to expend, in its discretion, no more than two hundred and fifty thousand dollars ($250,000) to terminate such Operating Emergency.

29.4 In the event the Operating Agent determines that the estimated amount required to terminate the Operating Emergency exceeds the amount which it is authorized to expend, the Operating Agent shall immediately notify the affected Parties following such determination. The Operating Agent shall provide the following information:

29.4.1 The estimated date when the Operating Emergency can be terminated.

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29.4.2 The person or persons who would perform the work and furnish the materials required to terminate the Operating Emergency.

29.4.3 The estimated amount of overtime, if any, which would be necessary in order to expedite the termination of the Operating Emergency.

29.4.4 The costs that are proposed to be capitalized, and salvage realized.

29.4.5 The costs that are proposed to be charged as maintenance expense.

29.4.6 The proposed administrative and general expense allowance applicable to such repair or reconstruction.

29.4.7 Such other information as may be necessary and required by the Engineering and Operating Committee to determine the manner in which the Operating Emergency is to be terminated.

29.5 The Engineering and Operating Committee shall review and approve the proposed repair or reconstruction, including the estimated cost thereof or shall agree upon an alternative.

29.6 Costs incurred in terminating an Operating Emergency may be billed to the Parties by the Operating Agent on the basis of its estimate of such costs with adjustment to be made in accordance with Section 29.8 when final cost determination has been made.

29.7 Following the termination of the Operating Emergency, the Operating Agent shall submit to the Parties a report containing a summary of the costs incurred and expenditures made in connection with the repair or reconstruction and such other information as may be required by the Engineering and Operating Committee.

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29.8 The Operating Agent shall allocate to the Parties the costs incurred or expenditures made in such repair or reconstruction, as follows: (i) costs charged as maintenance expense, in accordance with Section 22; and (ii) any other such repair or reconstruction costs, in accordance with Section 7.

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30.0 PAYMENT OF EXPENSES BY PARTIES:

30.1 All amounts required to be advanced by the Parties in accordance with this Agreement shall be made payable to the Operating Account established by the Operating Agent. The Operating Funds shall be owned by the Parties in proportion to their respective balances therein at any given time, and the Operating Agent in its capacity as such shall not have any right or title therein except to maintain custody of and to disburse the Operating Funds as a conduit between the Parties and those to whom such disbursements shall be made.

30.2 The Engineering and Operating Committee shall establish a minimum amount for the Operating Funds which will be available to pay for expenditures or obligations incurred by or on behalf of the Parties in accordance with this Agreement. Such minimum amount of Operating Funds may be revised by the Engineering and Operating Committee at any time. The minimum amount of the Operating Funds and any increases therein shall be advanced by the Parties in accordance with the percentages set forth in Section 22, and shall be due and payable within fifteen (15) business days following notification of the establishment of the minimum amount to be kept in Operating Funds or the date on which any increase in such amount authorized by the Engineering and Operating Committee shall become effective. In the event the Engineering and Operating Committee decreases such minimum amount, then each Party shall receive a credit which shall be equal to the product of its percentage, as set forth in Section 22, and the amount of any such decrease.

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30.3 Each Party shall advance Operating Funds on the basis of notices (hereinafter called bills) submitted by the Operating Agent reflecting such Party’s share of costs and expenses in accordance with this Agreement, as follows:

30.3.1 Expenses described in Sections 30 and 22 shall be billed in writing as follows:

30.3.1.1 The payroll costs to be paid to the Operating Agent’s employees for each pay period.

30.3.1.2 On the 20th day of each month, the total expenses incurred the previous month and described in Section 22 less those expenses billed under Section 30.3.1.1.

30.3.2 Bills submitted under Section 30.3.1 shall be due and payable within seven (7) business days following receipt of the bill.

30.3.3 Expenses described in Sections 31 and 23 shall be billed in writing at least ten (10) business days prior to their due date, and funds therefor shall be deposited with the Operating Agent not less than three (3) business days prior to their due date. If such bills do not have a specific due date, they shall be billed within a reasonable time following their incurrence.

30.3.4 Expenses described in Sections 7, 26, 27 and 29 shall be billed monthly, except when such expenses exceed the minimum amount in the Operating Funds in which case billing will be made immediately and payable within seven (7) business days following receipt of the bill.

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30.4 Except as expressly provided herein, nothing in this Agreement shall be deemed to require the Operating Agent to advance its own monies on any other basis than in its role, if any, as a Party.

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31.0 OPERATING INSURANCE:

31.1 Unless otherwise specified by the Coordination Committee, during the performance of Operating Work, the Operating Agent shall procure and maintain in force, or cause to be procured and maintained in force, policies of Operating Insurance providing coverage against the following risks, hazards and perils:

31.1.1 Risks covered by the standard form of commercial liability insurance, including bodily injury, personal injury and property damage risk, hazards of automobiles liability, contractual liability, contractor’s protective liability and liability for products and completed operations, in an amount not less than twenty-five million dollars ($25,000,000).

31.1.2 Risks covered by the standard form of “all risk” property insurance providing coverage against all risk of loss, except those risks excluded in the standard form of “all risk” property insurance. Such insurance shall provide boiler and pressure vessel coverage, including reasonable expediting expense.

31.1.3 Risks covered by the standard form of workers’ compensation and employers liability insurance, covering employees of the Operating Agent engaged in the performance of Operating Work, or other compliance by the Operating Agent with requirements of the laws of the State of New Mexico as to such coverage.

31.1.4 Risks covered by the standard form of employee dishonesty bond covering loss of property or funds due to dishonest or fraudulent acts committed by an officer or employee of the Operating Agent.

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31.2 Except for Operating Insurance described in Sections 31.1.3 and 31.1.4, each Party shall be a named insured individually and jointly and in accordance with its Participation Share as established in Section 6. Operating Insurance referred to in Section 31.1.1 shall carry cross-liability coverage.

31.3 In the event that another Party’s insurance program affords equal or better coverage on a more favorable cost basis than that available to the Operating Agent, the Parties may agree (by separate agreement) that such insurance program may be utilized to afford all or part of the insurance coverage required by Section 31.1.

31.4 The insurance company used, the insurable values, limits, deductibles, retentions and other special terms, covenants and conditions of the Operating Insurance shall be agreed upon by the Coordination Committee.

31.4.1 Any deductibles shall be shared by the Parties in accordance with the percentages established in Section 22.1.

31.5 The Operating Agent shall furnish each of the Parties with either a certified copy of each of the policies of Operating Insurance or a certified copy of each of the policy forms of Operating Insurance, together with a line sheet therefor (and any subsequent amendments) naming the insurers and underwriters and the extent of their participation. When the policies or policy forms of Operating Insurance have been approved in writing by all of the Parties, said policies or policy forms shall not be modified or changed by any Party without the prior written consent of all of the Parties, except for minor and insubstantial

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changes or modifications, as to which notification shall be given by the Operating Agent to the Parties.

31.6 Each of the Operating Insurance policies shall be endorsed so as to provide that all named insureds shall be given thirty (30) days notice of cancellation or material change.

31.7 Operating Insurance policies shall be primary insurance for all purposes and shall be so endorsed. Any insurance carried by a Party individually shall not participate with the Operating Insurance as respects any loss or claim for which valid and collectible Operating Insurance shall apply. Such other insurance shall apply solely as respects the individual interest of the Party carrying such other insurance.

31.8 Nothing herein shall prohibit the Operating Agent or any Party from furnishing a policy of Operating Insurance which combines the coverage required by this Agreement with coverage outside the scope of that required by this Agreement. If the Operating Agent or any Party furnishes a policy of Operating Insurance which combines the coverage required by this Agreement with coverage outside the scope of that required by this Agreement, the Coordination Committee shall agree on the portion of the total premium cost which is allocable to Operating Insurance. If the Parties are unable to agree on such allocation, the Operating Agent may make an estimated allocation and bill the Parties on the basis thereof, with adjustment to be made when the dispute is resolved.

31.9 If a Party desires changes in any Operating Insurance policy, such Party shall notify the Operating Agent and the other Parties in writing of the desired changes. Upon

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agreement of the Coordination Committee to such change, the Operating Agent shall obtain the insurance within sixty (60) days from the date of agreement. If the Operating Agent is unable to obtain the type of policy or coverage required herein or believed by the Operating Agent to be adequate, then the Operating Agent shall immediately notify the Parties.

31.10 In the event the Coordination Committee is unable to agree upon any matters relating to the Operating Insurance, the Operating Agent, pending the resolution of such disagreement, shall procure or cause to be procured such policies of insurance, consistent with Prudent Utility Practice, as are necessary to protect the Parties against the insurable risks for which Operating Insurance is required. During any period of negotiations with an insurer, or other negotiations which are pending at the expiration of the period of coverage of an Operating Insurance policy, or in the event an Operating Insurance policy is canceled, the Operating Agent shall renew or bind policies as an emergency measure, or may procure policies of insurance which are identical to those which were canceled, or may to the extent possible secure replacement policies which will provide substantially the same coverage as the policy expiring or canceled.

31.11 Each Party shall have the right to request that any mortgagee, trustee or secured party be named on all or any of the Operating Insurance policies as loss payees or additional assureds as their interests may appear. Such request shall be submitted to the Operating Agent specifying the name or names of such mortgagee, trustee or secured party and such additional information as may be necessary or required to permit it to be included on the policies of Operating Insurance.

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31.12 On an annual basis, the Operating Agent shall advise the Parties on the status of insurance coverage for the San Juan Project and shall make appropriate recommendations concerning insurance issues to the Coordination Committee.

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32.0 SURPLUS OR RETIRED PROPERTY:

The Operating Agent shall dispose of surplus property or property no longer used or useful in the operation of the San Juan Project and report such disposal to the Participants, both in accordance with practices and procedures established by the Engineering and Operating Committee. The proceeds from such disposition shall be credited to the Participants in accordance with their Participation Shares.

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33.0 REMOVAL OF OPERATING AGENT:

33.1 The Operating Agent shall serve as such during the term of this Agreement unless it resigns as Operating Agent by giving notice to the Parties at least one (1) year in advance of the date of resignation or until receipt by the Operating Agent of notice of its removal as provided in Section 33.2.

33.2 The Operating Agent may be removed as Operating Agent for any one of the following reasons:

33.2.1 The Operating Agent may be removed by action of the Coordination Committee if, in the judgment of the Coordination Committee (voting as provided for in Section 18.4), the best interests of the San Juan Project require that a new Operating Agent be selected. Any Party seeking a Coordination Committee determination to remove the Operating Agent shall provide to the Operating Agent and to all of the Parties a written statement, detailing the reasons why, in the judgment of the initiating Party, the Operating Agent should be removed. Within thirty (30) days after receipt by the Operating Agent of this written statement, the Operating Agent shall prepare and serve upon all of the Parties its response which shall contain a detailed rebuttal of the allegations made in the initiating statement. Within the same thirty (30) day period, any other Party may also prepare and serve upon the Operating Agent and the Parties a statement responding to the allegations in the initiating statement. Within twenty (20) days after service of all such response statements, the Coordination Committee shall meet to consider what

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action, if any, to take with regard to the removal of the Operating Agent. If, pursuant to this Section 33.2.1, the Coordination Committee removes the Operating Agent, such removal shall be effective upon the date established by the Coordination Committee. If the Operating Agent or any Party is dissatisfied with the action of the Coordination Committee, it shall have the right to seek arbitration under Section 37, but no demand for arbitration shall stay the decision of the Coordination Committee to remove the Operating Agent.

33.2.2 If, pursuant to the provisions of Section 34, it is determined that the Operating Agent is in default of its obligations under this Agreement, the Operating Agent may be removed by written notice given by any Party under Section 34.1.2, which notice shall state the effective date of the removal of the Operating Agent.

33.2.3 Notwithstanding the pendency of any actions to remove the Operating Agent, the Operating Agent shall continue in good faith to exercise its obligations as Operating Agent.

33.3 Prior to the effective date of a resignation of the Operating Agent, or prior to the date of removal of the Operating Agent in accordance with Section 33.2, the Coordination Committee shall by written agreement designate a new Operating Agent, which may, but need not, be a Party. The Coordination Committee may designate an interim Operating Agent pending selection of a permanent Operating Agent. Acceptance by the new Operating Agent of its appointment as such shall constitute its agreement to perform the obligations of the Operating Agent under this Agreement.

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34.0 DEFAULTS BY OPERATING AGENT:

34.1 The following provisions shall apply solely in regard to violations or allegations of violations of this Agreement by the Operating Agent on the basis of which removal of the Operating Agent is sought:

34.1.1 In the event any Party shall be of the opinion that an action taken or failed to be taken by the Operating Agent constitutes a violation of this Agreement, it may give written notice thereof to the Operating Agent and the other Parties, together with a statement of the basis for its opinion. Thereupon, the Operating Agent may prepare a statement of the reasons justifying its action or failure to take action. If agreement in settling the dispute is not reached between the Operating Agent and such Party which gave such notice, then the matter shall be submitted to arbitration in the manner provided in Section 37. During the continuance of the arbitration proceedings, the Operating Agent may continue such action taken or failed to be taken in the manner it deems most advisable and consistent with this Agreement.

Party is of the opinion that the Operating Agent has not taken such action to correct,

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or to commence action to correct, the violation within such allowed period, the complaining Party shall be entitled to submit the question of the Operating Agent’s good faith action to terminate such violation to arbitration as provided in Section 37. If it is determined that the Operating Agent has not acted with due diligence or good faith to terminate such violation, it shall be deemed to be in default and shall be subject to removal, after the arbitration determination, within fifteen (15) days after receipt of notice executed by the complaining Party in accordance with Section 42.

34.1.3 The provisions of Section 35, excepting Sections 35.8 and 35.9, shall not apply to disputes as to whether or not an action or non-action of the Operating Agent, in its capacity as Operating Agent, is a violation or default under this Agreement.

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PART VII

DEFAULTS, LIABILITY AND ARBITRATION

35. DEFAULTS:

35.1 Each Party shall pay all monies and carry out all other performances, duties and obligations agreed to be paid or performed by it pursuant to all of the terms and conditions set forth and contained in the Project Agreements, and a default by any Party in the covenants and obligations to be by it kept and performed pursuant to the terms and conditions set forth and contained in any of the Project Agreements shall be an act of default under this Agreement. A default under the Mine Reclamation Agreement or the Decommissioning Agreement is not a default under this Agreement. If a Party breaches a performance obligation under Sections 4.3 or 5 of the Restructuring Agreement, which provisions are incorporated in Sections 7.13.1 and 23 of this Agreement, the non-defaulting Parties’ remedies shall be as provided in this Agreement. A default under any other section of the Restructuring Agreement shall not be a default under this Agreement, irrespective of whether it is incorporated in this Agreement, and remedies for such a default shall be as provided in the Restructuring Agreement.

35.2 In the event of a default by a Party in any of the terms and conditions of this Agreement to be performed by that Party, the following shall apply:

35.2.1 The Operating Agent shall give a written notice of the default to the defaulting Party and the other Parties in accordance with Section 35.2.2.

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35.2.2 The notice of default shall specify the existence, nature and extent of the default. Upon receipt of the notice of default, the defaulting Party shall immediately take all steps necessary to cure the default as promptly and completely as possible.

35.3 In the event that any Party shall dispute an asserted default by it, then such Party shall pay the disputed payment or perform the disputed obligation, but may do so under protest. The protest shall be in writing, shall accompany the disputed payment or precede the performance of the disputed obligation(s), and shall specify the reason upon which the protest is based. Copies of such protest shall be mailed by such Party to all other Parties and to the Operating Agent. Payments not made under protest shall be deemed correct, except to the extent that periodic or annual audits may reveal over or under payment by a Party or may necessitate adjustments. In the event it is determined by arbitration, pursuant to the provisions of this Agreement or otherwise, that the protesting Party is entitled to a refund of all or any portion of a disputed payment or payments, or is entitled to the reasonable equivalent in money of non-monetary performance of a disputed obligation theretofore made, then, upon such determination, the non-protesting Party(ies) shall reimburse such amount to the protesting Party, together with interest thereon at the rate of ten percent (10%) per annum, or the maximum legal rate of interest, whichever is lesser, from the date of payment or of the performance of a disputed obligation to the date of reimbursement.

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35.4 In the event a default shall continue for a period of ten (10) days or more after the notice given by the Operating Agent in accordance with Section 35.2 without having been cured by the defaulting Participant, or without such defaulting Party having commenced or continued action in good faith to cure such default, the following shall apply:

35.4.1 If the defaulting Party has failed to cure such default or to commence such good faith action during said ten (10) day period, the Operating Agent shall make a written report to the Engineering and Operating Committee concerning the status of the default and shall, on the next working day after such ten (10) day period, notify the defaulting Party in writing that the Operating Agent intends to declare the defaulting Party in default under the Project Agreements unless there is a prompt cure of the default. Seven (7) days after the giving of such notice to the defaulting Party, the Operating Agent shall make a second written report to the Engineering and Operating Committee concerning the status of the default and the efforts, if any, of the defaulting Party to cure the default. If, within seven (7) additional days, the defaulting Party has neither cured nor reasonably commenced to cure the default, the Operating Agent shall declare the defaulting Party in default under the Project Agreements and shall provide written notification of the declaration of default to the defaulting Party and to the Engineering and Operating Committee. Thereafter, and for so long as the default is not remedied and the declaration of default is not revoked by the Operating Agent, all rights of the

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defaulting Party under the Project Agreements shall be suspended, including the right to vote on all committees and to receive all or any part of its proportionate share of the Net Effective Generating Capacity.

35.4.2 Within seventeen (17) days after the notice by the Operating Agent, as provided for in Section 35.2, the Operating Agent shall prepare special operating procedures for approval by the Engineering and Operating Committee that will apply during the period of suspension under Section 35.4.1. Upon approval by the Engineering and Operating Committee, the Operating Agent shall provide notice to each Party of such special procedures. These special procedures shall include:

35.4.2.1 A tabulation in form similar to Section 6.2 of the percentages of costs to be borne by the non-defaulting Parties pursuant to Section 35.5;

35.4.2.2 Billing and accounting of such costs;

35.4.2.3 Dispatch and scheduling of the defaulting Party’s proportionate share of Net Effective Generating Capacity; and

35.4.2.4 Any other items required for the optimal use of the San Juan Project and the mitigation of damages by the non-defaulting Parties.

35.4.2.5 If the Operating Agent proposes to broker all or a portion of the defaulting Party’s proportionate share of Net Effective Generating Capacity on behalf of one or more non-defaulting Parties, the form of such an agreement shall be incorporated in such procedures.

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35.4.3 Within twenty (20) days after the declaration of a default, as provided for in Section 35.4.1, the defaulting Party and the non-defaulting Parties shall convene a meeting to address the defaulting Party’s situation and its intentions with regard to curing its default. The defaulting Party shall promptly prepare a cure plan for approval by the members of the Coordination Committee entitled to vote thereon. The cure plan shall address the defaulting Party’s plan to cure the default and restore itself to full participation as an owner of the San Juan Project. The Coordination Committee, by vote of the members of the Coordination Committee entitled to vote thereon, will monitor the defaulting Party’s compliance with the terms and conditions of the cure plan and if it appears to the Coordination Committee that the defaulting Party is or will be unable to comply with the terms of an approved cure plan, the Coordination Committee shall consider what actions may be required to address such inability, including, but not limited to, directing the Operating Agent to take such actions as may be appropriate. It is the intent of the Parties that any defaults shall be cured on as expeditious a basis as reasonably possible.

35.4.4 A demand for arbitration of an asserted default pursuant to Section 37 shall not stay the suspension of the rights of the defaulting Party, but in the event that the board of arbitrators shall determine that the asserted default did not in fact exist or occur, the arbitrators shall specify a method of fully and fairly compensating the Party which, under Section 35.4.1, was denied the right to vote on committee

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actions and to receive all or any part of its proportionate share of the Net Effective Generating Capacity.

35.5 During any period when the suspension provided for in Section 35.4.1 is in effect, the non-defaulting Party(ies) having a Participation Share in the affected Unit or Units: (i) shall bear a proportionate share of all expenses, including but not limited to, the operation and maintenance costs, insurance costs, fuel costs, capital expenditures and other expenses otherwise payable by the defaulting Party under the Project Agreements, including any obligations related to common equipment and facilities, based upon the relation of the Participation Share of each such non-defaulting Party(ies) to the Participation Shares of all non-defaulting Parties in the specific Unit or Units; and (ii) shall be entitled to schedule and receive for their accounts their proportionate share of the Net Effective Generating Capacity of the defaulting Party.

35.6 In connection with its cure of the default, the defaulting Party shall pay promptly upon demand to the non-defaulting Party(ies) the total amount of money (and/or the reasonable equivalent in money of non-monetary performance) paid and/or made by such non-defaulting Party(ies) pursuant to Section 35.5 in order to cure any default by the defaulting Party, together with interest thereon at the rate of ten percent (10%) per annum, or the maximum legal rate of interest, whichever is the lesser, from the date of the expenditure of such money (or the making of such other performance) by the non-defaulting Party(ies), to the date of such reimbursement by the defaulting Party, or such greater amount as may be otherwise provided in the Project Agreements. Any payment obligation of the

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defaulting Party shall be reduced by mitigation measures undertaken by the non-defaulting Parties; provided, however, that the payment obligations of the defaulting Party shall not be reduced by any profits or gains achieved by the non-defaulting Parties as the result of taking a proportionate share of the Net Effective Generating Capacity due to the default of the defaulting Party.

35.7 The suspension of a defaulting Party shall be terminated and its full rights under the Project Agreements restored when the default(s) have been cured and all compensable costs incurred by the non-defaulting Party(ies) hereunder have been paid by the defaulting Party or other arrangements acceptable to the non-defaulting Party(ies) have been made.

35.8 No waiver by a non-defaulting Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall be effective unless the non-defaulting Party(ies) waive in writing their respective rights and any such waiver shall not be deemed to be a waiver with respect to any subsequent default or matter. No delay short of the statutory period of limitations in asserting or enforcing any right hereunder shall be deemed a waiver of such right.

35.9 The rights and remedies provided in this Agreement shall be in addition to the rights and remedies of the Parties as set forth and contained in any other Project Agreement or any rights and remedies the Parties have in law or equity.

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36.0 LIABILITY:

36.1 Except for any judgment debt for damage resulting from Willful Action and except to the extent any judgment debt is collectible from valid insurance, and subject to the provisions of Sections 36.1.1, 36.4, 36.5, 36.6 and Section 37, each Party hereby extends to all other Parties, their directors, members of their governing bodies, officers and employees, its covenant not to execute, levy or otherwise enforce a judgment obtained against any of them, including recording or effecting a judgment lien, for any direct, indirect, or consequential loss, damage, claim, cost, charge or expense, whether or not resulting from the negligence of such Party, its directors, members of its governing body, officers, employees or any person or entity whose negligence would be imputed to such Party from (i) Operating Work, the design and construction of Capital Improvements or the use or ownership of the San Juan Project or (ii) the performance or nonperformance of the obligations of any Party under any of the Project Agreements, other than the obligation to pay any monies becoming due.

36.1.1 In the event any insurer providing insurance refuses to pay any judgment obtained by a Party against any other Party, its directors, members of its governing body, officers or employees on account of liability referred to in Section 36.1, the Party, its directors, members of its governing body, officers or employees against whom the judgment is obtained shall, at the request of the prevailing Party and in consideration for the covenant granted in Section 36.1, execute such documents as may be necessary to effect an assignment of its

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contractual rights against the nonpaying insurer and thereby give the prevailing Party the opportunity to enforce its judgment directly against such insurer. In no event when a judgment debt is collectible from valid insurance shall the Party obtaining the judgment execute, levy or otherwise enforce the judgment (including recording or effecting a judgment lien) against the Party, its directors, members of its governing body, officers or employees against whom the judgment was obtained.

36.1.2 To the extent that Section 41‑3‑5, New Mexico Statutes Annotated, 1978 compilation (as such section may be amended), shall be applicable and for the purpose of relieving each Party, its directors, members of its governing body, officers and employees of any liability to make contribution to other non‑Party tortfeasors, the foregoing covenant not to execute hereby effects a reduction of all injured Parties’ damages recoverable against all other non‑Party tortfeasors to the extent of the pro rata share (as referred to in Section 41‑3‑5, New Mexico Statutes Annotated, 1978 compilation, as such section may be amended) of the other Parties, their directors, members of their governing bodies, officers and employees.

36.1.3 Each Party agrees, upon request by any other Party, to make, execute and deliver any and all documents or take such other action as may reasonably be required to effectuate the intent of this Section 36.1.

36.2 Except as provided in Sections 36.4, 36.5 and 36.6, the costs and expenses of discharging all work liability imposed upon one or more of the Parties, for which payment is not made by insurance, shall be allocated among the Parties in proportion to

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their respective Participation Shares in the property giving rise to the work liability. Work liability is defined as liability of one or more Parties for any loss, damage, claim, cost, charge or expense of any kind or nature (including direct, indirect or consequential) suffered or incurred by any party other than a Party, whether or not resulting or to result in the future from the negligence of any Party, its directors, members of its governing body, officers, employees or any other person or entity whose negligence would be imputed to such Party, that has resulted or may result in the future from (i) performance or nonperformance of the work herein described, (ii) operation, maintenance, use or ownership of the San Juan Project, and (iii) past or future performance or nonperformance of the obligations of any Party under any of the Project Agreements.

36.3 If it cannot be determined which property gave rise to work liability, the allocation for discharging costs and expenses associated therewith shall be as specified in Section 22.1.7.

36.4 Except for liability resulting from Willful Action (which subject to the provisions of Section 36.6 shall be the responsibility of the willfully acting Participant), any Party whose electric customer shall have a claim or bring an action against any other Party for any death, injury, loss or damage arising out of or in connection with electric service to such customer caused by the operation or failure of operation of the San Juan Project or any portion thereof shall indemnify and hold harmless such other Party, its directors, members of its governing body, officers and employees from and against any liability for such death, injury, loss or damage.

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36.5 Each Party shall be responsible for any damage, loss, claim, cost, charge or expense that is not covered by insurance and results from its own Willful Action as defined in Section 5.57.2 and shall indemnify and hold harmless the other Parties, their directors, members of their governing bodies, officers and employees, from any such damage, loss, claim, cost, charge or expense.

36.6 Except as provided in Section 36.5, the aggregate liability of any Party to all other Parties for Willful Action not covered by insurance shall be determined as follows:

36.6.1 All such liability for damages, losses, claims, costs, charges or expenses of such Party shall not exceed ten million dollars ($10,000,000) per occurrence. Each Party extends to each other Party, its directors, members of its governing body, officers and employees its covenant not to execute, levy or otherwise enforce a judgment against any of them for any such aggregate liability in excess of ten million dollars ($10,000,000) per occurrence.

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established in Section 36.6.1; (ii) When all pending suits are resolved, those Parties who were awarded judgments or reached settlements but whose claims were not fully satisfied pursuant to Section 36.6.2(i) shall be entitled to participate in any remaining portion of the ten million dollar ($10,000,000) maximum recovery limit, based upon the ratio of the unsatisfied portion of such Party’s judgment or settlement to the total unsatisfied portion of all such judgments and settlements. Such participation shall be limited to the Parties’ unsatisfied judgments or settlements.

36.7 The provisions of this Section 36 shall not be construed so as to relieve any insurer of its obligation to pay any insurance proceeds in accordance with the terms and conditions of valid and collectible insurance policies.

36.8 If a court of competent jurisdiction determines upon a challenge by a Party or third party that the provisions of Section 56-7-1, New Mexico Statutes Annotated, 1978 Compilation, as amended, are applicable to this Agreement, the Parties agree that any agreement to indemnify contained in this Agreement shall be enforced only to the extent it requires the indemnitor to indemnify or hold harmless the indemnitee, including its officers, employees or agents, against liability, claims, damages, losses or expenses, including attorney’s fees, only to the extent that the liability, damages, losses or costs are caused by, or arise out of, the acts or omissions of the indemnitor or its officers, employees or agents.

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36.9 The Parties agree that the aggregate liability limit of ten million dollars ($10,000,000) referenced in Sections 36.6.1 and 36.6.2 may be determined in the future to be inappropriate and shall, at the request of any Party, make a good faith effort to evaluate and, if appropriate, revise said limit.

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37.0 ARBITRATION:

37.1 If a dispute between or among any of the Parties (which term, for purposes of this Section 37, shall be deemed to include the Operating Agent) should arise in relation to the performance or nonperformance of any obligation under this Agreement, any Party(ies) may call for submission of the dispute to arbitration, which call shall be binding upon all of the other affected Party(ies). Disputes arising under the Mine Reclamation Agreement and the Decommissioning Agreement shall be resolved pursuant to the dispute resolution provisions of those agreements. Disputes arising under Sections 4.3 or 5 of the Restructuring Agreement, which provisions are incorporated into Sections 7.13.1 and 23 of this Agreement, shall be resolved pursuant to the dispute resolution provisions of this Agreement. Any other disputes arising under the Restructuring Agreement shall be resolved pursuant to the dispute resolution provisions of the Restructuring Agreement.

37.2 The Party(ies) calling for arbitration shall give written notice to all other Parties, setting forth in such notice in adequate detail the entity(ies) against whom relief is sought, the nature of the dispute, the amount or amounts, if any, involved in such dispute, and the remedy sought by such arbitration proceedings. Within twenty (20) days after receipt of such notice, any other Party(ies) involved may, by written response to the first Party(ies), as well as the other Party(ies), submit its or their own statement of the matter at issue and set forth in adequate detail additional related matters or issues to be arbitrated. Thereafter, the Party(ies) first submitting its or their notice of the matter at issue shall have

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ten (10) days in which to submit a written rebuttal statement, copies of which shall be provided to all other Parties.

37.3 Within ten (10) days following delivery of the last written submittal pursuant to Section 37.2, the affected Party(ies), acting through their respective representatives, shall meet for the purpose of selecting arbitrators. Each affected Party, or group of Parties, representing one side of the dispute, shall designate an arbitrator. The arbitrators so selected shall meet within twenty (20) days following their selection and shall select additional arbitrator(s), the number of which additional arbitrators shall be one (1) less than the total number of arbitrators selected by the affected Parties. If the arbitrators selected by the affected Parties, as herein provided, shall fail to select such additional arbitrator(s) within said twenty (20) day period, then the arbitrators shall request from the American Arbitration Association (or similar organization if the American Arbitration Association should not exist at the time) a list of arbitrators who are qualified and eligible to serve as hereinafter provided. The arbitrators selected by the affected Parties shall take turns striking names from the list of arbitrators furnished by the American Arbitration Association, and the last name(s) remaining on said list shall be the additional arbitrator(s). All arbitrators shall be persons skilled and experienced in the field which gives rise to the dispute, and no person shall be eligible for appointment as an arbitrator who is an officer or employee of any of the Parties to the dispute or is otherwise interested in the matter to be arbitrated.

37.4 Except as otherwise provided in this Section 37 or otherwise agreed by the Parties to the dispute, the arbitration shall be governed by the rules and practices of the

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American Arbitration Association (or rules and practices of a similar organization if the American Arbitration Association should not exist at that time) from time to time in force, except that if such rules and practices, as modified herein, shall conflict with New Mexico Rules of Civil Procedure or any other provisions of New Mexico law then in force which are specifically applicable to arbitration proceedings, such New Mexico laws shall govern.

37.5 Included in the issues which may be submitted to arbitration pursuant to this Section 37 is the issue of whether the right to arbitrate a particular dispute is permitted under the Project Agreements.

37.6 The arbitrators shall hear evidence submitted by the respective Parties or group or groups of Parties and may call for additional information, which additional information shall be furnished by the Party having such information. The decision of a majority of the arbitrators shall be binding upon all the Parties and shall be based on the provisions of the Project Agreements and New Mexico law.

37.7 This agreement to arbitrate shall be specifically enforceable and the award of the arbitrators shall be final and binding upon the Parties to the extent provided by the laws of the State of New Mexico. Any award may be filed with the clerk of any court having jurisdiction over the Parties or any of them against whom the award is rendered, and, upon such filing, such award, to the extent permitted by the laws of the jurisdiction in which said award is filed, shall be specifically enforceable or shall form the basis of a declaratory judgment or other similar relief.

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37.8 Each Party or group of Parties shall be responsible for the fees and expenses of the arbitrator selected by that Party or group of Parties, unless the decision of the arbitrators shall specify some other apportionment of such fees and expenses. The fees and expenses of the neutral arbitrators shall be shared among the affected Parties equally, unless the decision of the arbitrators shall specify some other apportionment of such fees and expenses. All other expenses and costs of the arbitration, including attorney fees, shall be borne by the Party incurring the same.

37.9 In the event that any Party(ies) shall attempt to institute or to carry out the provisions herein set forth in regard to arbitration, and such Party(ies) shall not be able to obtain a valid and enforceable arbitration decree, such Party(ies) shall be entitled to seek legal remedies in a court having jurisdiction in the premises, and the provisions in this Section 37 referring to arbitration decisions shall then be deemed applicable to final decisions of such court.

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PART VIII

RETIREMENT AND RECONSTRUCTION

38.0 DESTRUCTION, DAMAGE OR CONDEMNATION OF A UNIT:

38.1 If all, or substantially all, of a Unit is destroyed, damaged or condemned, then the Participants with Participation Shares in that Unit by unanimous agreement may elect to repair or reconstruct the damaged, destroyed or condemned Unit in such a manner as to restore the Unit to substantially the same general character or use as the original, or to such other character or use as the Participants may then mutually agree. In the event of such election, it shall be the obligation of the Participants to pay for the costs of such repair or reconstruction in accordance with the Participation Shares of the respective Participants in such Unit, and, upon completion thereof, the Participants’ rights, titles and interests therein shall be as provided in this Agreement. The retirement of Units 2 and 3 shall not be within the scope of this Section 38.

38.2 Failure to reach unanimous agreement as provided in Section 38.1 shall be deemed to be an election not to repair or reconstruct the damaged, destroyed or condemned Unit, in which event the proceeds from any insurance or from any award shall be distributed to the Participants in accordance with their respective Participation Shares in such Unit. The facilities not destroyed, damaged or condemned shall be disposed of by the Participants in a manner to be mutually agreed upon, and the proceeds from such disposition shall be distributed in accordance with the Participation Shares of the respective Participants in such Unit. Nothing in this section shall be deemed to preclude any Participant or group of

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Participants in the Unit from agreeing to repair, reconstruct or replace the damaged, destroyed or condemned Unit.

38.3 In the event that less than substantially all of a Unit is destroyed, damaged or condemned, then it shall be the obligation of the Participants having a Participation Share in such Unit to repair or reconstruct such Unit. Each Participant shall be obligated to pay its proportionate share of the costs of such repair or reconstruction in accordance with Section 6.2.

38.4 In the event that any common equipment and/or facility is destroyed, damaged or condemned, then it shall be the obligation of the Participants having a Participation Share in such common equipment and/or facilities to repair or reconstruct such damaged, destroyed or condemned equipment and/or facilities. Each Participant shall be obligated to pay its proportionate share of the costs of such repair or reconstruction in accordance with Section 6.2.

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39.0 RIGHTS OF PARTICIPANTS UPON TERMINATION:

39.1 In the event the Participants by unanimous agreement abandon, retire or otherwise terminate or suspend operation of the San Juan Project prior to the termination of this Agreement, the facilities forming the San Juan Project shall be disposed of by the Participants in a manner to be unanimously agreed upon and the proceeds from such disposition shall be distributed to the Participants in accordance with their respective Participation Shares.

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40.0 DECOMMISSIONING OF THE PROJECT:

40.1 The Participants acknowledge the appropriateness of incorporating in a future amendment to this Agreement, or in another appropriate contractual instrument, provisions which address the decommissioning of the San Juan Project and/or of one or more Units. It is recognized, however, that the resolution of issues associated with San Juan Project decommissioning will require protracted study. The Participants therefore agree to establish a task force or other forum for the careful and deliberate consideration of decommissioning issues so that these issues may be addressed and resolved in a timely manner. The Operating Agent shall propose to the Participants a methodology and a schedule for addressing decommissioning issues.

40.2 In recognition of, and in order to implement Section 40.1, upon the effective date of the Decommissioning Agreement, the decommissioning of the San Juan Project shall be governed by the Decommissioning Agreement.

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PART IX

MISCELLANEOUS PROVISIONS

41.0 RELATIONSHIP OF PARTIES:

41.1 The covenants, obligations and liabilities of the Parties are intended to be several and not joint or collective, and nothing herein contained shall ever be construed to create an association, joint venture, trust or partnership, or to impose a trust or partnership covenant, obligation or liability on or with regard to any one or more of the Parties. Each Party shall be individually responsible for its own covenants, obligations and liabilities as herein provided. No Party or group of Parties shall be under the control of or shall be deemed to control any other Party or the Parties as a group. No Party shall be the agent of or have a right or power to bind any other Party without its express written consent, except as expressly provided herein.

41.2 The Parties hereby elect to be excluded from the application of Subchapter “K” of Chapter 1 of Subtitle “A” of the Internal Revenue Code of 1986, or such portion or portions thereof as may be permitted or authorized by the Secretary of the Treasury or its delegate insofar as such subchapter, or any portion or portions thereof, may be applicable to the Parties hereunder.

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42.0 NOTICES:

42.1 Any notice, demand or request provided for in this Agreement, or served, given or made in connection with it, shall be deemed properly served, given or made (i) when delivered personally or by prepaid overnight courier, with a record of receipt, (ii) the fourth day if mailed by certified mail, return receipt requested, or (iii) the day of transmission, if sent by facsimile or electronic mail during regular business hours or the day after transmission, if sent after regular business hours (provided however, that such facsimile or electronic mail shall be followed on the same day or next business day with the sending of a duplicate notice, demand or request by a nationally recognized prepaid overnight courier with record of receipt), to the persons specified below:

42.1.1 Public Service Company of New Mexico

Attn: Vice President, PNM Generation

2401 Aztec NE, Bldg. A

Albuquerque, NM 87107

With a copy to:

Public Service Company of New Mexico

c/o Secretary

414 Silver Ave. SW

Albuquerque, New Mexico 87102

42.1.2 Tucson Electric Power Company

88 E. Broadway Blvd.

MS HQE901

Tucson, Arizona 85701

Attn: Corporate Secretary

42.1.3 City of Farmington

c/o City Clerk

800 Municipal Drive

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Farmington, NM 87401

With a copy to:

Farmington Electric Utility System

Electric Utility Director

101 North Browning Parkway

Farmington, NM 87401

42.1.4 M-S-R Public Power Agency

c/o General Manager

1231 11 ^th Street

Modesto, CA 95354

42.1.5 Southern California Public Power Authority

c/o Executive Director

1160 Nicole Court

Glendora, CA 91740

42.1.6 City of Anaheim

c/o City Clerk

200 South Anaheim Boulevard

Anaheim, CA 92805

With a copy to:

Public Utilities General Manager

201 South Anaheim Boulevard

Suite 1101

Anaheim, CA 92805

42.1.7 Incorporated County of

Los Alamos, New Mexico

c/o County Clerk

1000 Central Ave.

Suite 240

Los Alamos, NM 87544

with a copy to:

Incorporated County of

Los Alamos, New Mexico

c/o Utilities Manager

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1000 Central Ave.

Suite 130

Los Alamos, NM 87544

42.1.8 Utah Associated Municipal Power Systems

c/o General Manager

155 North 400 West

Suite 480

Salt Lake City, UT 84103

42.1.9 Tri-State Generation and Transmission

Association, Inc.

c/o Chief Executive Officer

1100 West 116 ^th Avenue

Westminster, CO 80234

Or P. O. Box 33695

Denver, CO 80233

For purposes of overnight courier service, Tri-State’s address is:

Tri-State Generation and Transmission Association, Inc.

c/o Chief Executive Officer

3761 Eureka Way

Frederick, CO 80516

42.1.10 PNMR Development and Management Corporation

c/o Corporate Secretary

PNM Resources, Inc.

Corporate Headquarters

414 Silver Avenue SW

Albuquerque, NM 87158-1245

42.2 A Party may, at any time or from time to time, by written notice to the other Parties, change the designation or address of the person so specified as the one to receive notices pursuant to this Agreement.

42.3 The Operating Agent shall provide to each Party a copy of any material notice, demand or request given or received by it in connection with the San Juan Project.

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43.0 OTHER PROVISIONS:

43.1 Each Party agrees, upon request by another Party, to make, execute and deliver any and all documents reasonably required to implement the terms of this Agreement.

43.2 No Party shall be considered to be in default in the performance of any of the obligations hereunder (other than obligations of a Party to pay costs and expenses) if failure of performance shall be due to uncontrollable forces. The term “uncontrollable forces” shall mean any cause beyond the control of the Party affected, including but not limited to failure of facilities, flood, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance, labor dispute, sabotage or terrorism, restraint by court order or public authority, or failure to obtain approval from a necessary governmental authority which by exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by exercise of due diligence it shall be unable to overcome. Nothing contained herein shall be construed so as to require a Party to settle any strike or labor dispute in which it may be involved. Any Party rendered unable to fulfill any obligation by reason of uncontrollable forces shall exercise due diligence to remove such inability with all reasonable dispatch.

43.3 The captions and headings appearing in this Agreement are inserted merely to facilitate reference and shall have no bearing upon the interpretation of the provisions hereof.

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43.4 This Agreement is made under and shall be governed by the laws of the State of New Mexico, without regard to conflicts of law principles.

43.5 The covenants and obligations set forth and contained in this Agreement are to be deemed to be independent covenants, not dependent covenants, and the obligation of a Party to perform all of the obligations and covenants to be by it kept and performed is not conditioned on the performance by another Party of all of the covenants and obligations to be kept and performed by it.

43.6 In the event that any of the terms or conditions of this Agreement, or the application of any such term or condition to any person or circumstance, shall be held invalid by any court having jurisdiction in the premises, the remainder of this Agreement, and the application of such terms or conditions to persons or circumstances other than those as to which it is held invalid, shall not be affected thereby.

43.7 All costs or expenses, including all taxes that the Operating Agent is required to pay (but not specifically referred to in other sections of this Agreement), which are incurred by the Operating Agent in connection with the performance of its obligations under this Agreement and which are not specifically allocated to the Parties in accordance with this Agreement shall be equitably allocated among the Parties in a manner to be established by the Coordination Committee.

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within the reasonable contemplation of the Parties at the time of the execution of this Agreement, the Parties, including the Operating Agent, shall negotiate in good faith in order that an appropriate and equitable adjustment shall be made in the reimbursement of the Operating Agent and in the allocation of expenses among the Parties. Such adjustment shall be fair and equitable as to both the Operating Agent and the other Parties.

43.9 The execution of this Agreement shall not affect any rights or obligations of the Parties which shall have accrued prior to or coincident with the effective date of this Agreement, including any obligation to pay money or take other actions in accordance with the Original San Juan PPA, the Amended and Restated San Juan PPA, the UG-CSA, the Co-Tenancy Agreement, the Operating Agreement, the Restructuring Agreement, the Decommissioning Agreement, the Mine Reclamation Agreement, the UG-CSA Termination Agreement, the CCBDA Termination Agreement or any other San Juan Project-related agreement.

43.10 Except as provided in Sections 35.1 and 37.1, to the extent of any conflict between this Agreement and the Restructuring Agreement, the provisions of the Restructuring Agreement shall control.

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44.0 EXECUTION IN COUNTERPARTS:

44.1 This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument as if all the Parties to the aggregated counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart thereof without impairing the legal effect of any signatures thereon and may be attached to any other counterpart of this Agreement identical in form thereto but having attached to it one or more additional pages. Electronic or pdf signatures have the same effect as an original signature.

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45.0 AMENDMENTS:

45.1 Except as provided in Section 45.2, this Agreement may be amended only by written instrument executed by all of the Parties with the same formality as this Agreement.

45.2 The Coordination Committee, by unanimous vote, may amend any one or more of the exhibits attached to this Agreement. In the event of any such action by the Coordination Committee, a copy of the new exhibit shall be attached to this Agreement to replace the old or superseded exhibit, without the necessity of formally amending this Agreement. Any such action shall not affect other provisions of this Agreement, including other exhibits thereto.

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IN WITNESS WHEREOF , the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By_ /s/ Chris M. Olson ___________________

Its__ Vice President Generation __________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

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IN WITNESS WHEREOF , the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By _ /s/_Mark Mansfield _________________

Its __ VP Energy Resources _________ __

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

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IN WITNESS WHEREOF , the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By _ /s/ _ Robert Mayes ______________________

Its__ City Manager ______________________

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

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IN WITNESS WHEREOF , the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

M-S-R PUBLIC POWER AGENCY

By__ /s/_Martin Hopper _____________________

Its___ General Manager __________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

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IN WITNESS WHEREOF , the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By ___ /s/ Kristin Henderson __________________

Its ___ Council Chair ______________________

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SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By _/s/ Fred Mason _________________________

Its __ President ______________________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By______________________________________

Its____________________________________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

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SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

APPROVED AS TO FORM:

MICHAEL R.W. HOUSTON, CITY ATTORNEY

By: __/s/_Dukku Lee_______________ BY ________ _/s/ Alison M. Kott 7-27-15___

Dukku Lee Alison M. Kott, Assistant City Attorney

Public Utilities General Manager

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By______________________________________

Its____________________________________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

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SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By __/s/ Douglas Hunter _____________________

Its__ General Manager ____________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By______________________________________

Its____________________________________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

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SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By __/s/_Micheal McInnes __________________

Its___ CEO _____________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

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SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By______________________________________

Its____________________________________

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By __ _ /s/ Elisabeth Eden _______________________

Its_ President, Chief Executive Officer and Treasurer

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STATE OF NEW MEXICO )

)ss.

COUNTY OF BERNALILLO )

The foregoing instrument was acknowledged before me on this _ 30th _ day of June , 2015, by _ Chris M. Olson ___, _____ VP, Generation ________________ of Public Service Company of New Mexico, a New Mexico corporation, on behalf of the corporation.

/s/ Patricia A. Salls

Notary Public

My commission expires:

September 14, 2018

STATE OF ARIZONA )

)ss.

COUNTY OF PIMA )

The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Tucson Electric Power Company, an Arizona corporation, on behalf of the corporation.

Notary Public

My commission expires:

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STATE OF NEW MEXICO )

)ss.

COUNTY OF BERNALILLO )

The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Public Service Company of New Mexico, a New Mexico corporation, on behalf of the corporation.

Notary Public

My commission expires:

STATE OF ARIZONA )

)ss.

COUNTY OF PIMA )

The foregoing instrument was acknowledged before me on this _ 1 ^st __ day of _ July ____, 2015, by _ Mark ____________, _ Mansfield __________________ of Tucson Electric Power Company, an Arizona corporation, on behalf of the corporation.

/s/ Cheryl T. Gottshall

Notary Public

My commission expires:

June 30, 2018

173 Restructuring Amendment 7/31/2015

EXECUTION VERSION

STATE OF NEW MEXICO )

)ss.

COUNTY OF SAN JUAN )

The foregoing instrument was acknowledged before me on this _ 1st __ day of _ July ____, 2015, by _ Robert Mayes _______________, _ City Manager __________ of The City of Farmington, New Mexico, a New Mexico municipal corporation, on behalf of the municipal corporation.

/s/ Melody A. Coyner

Notary Public

My commission expires:

05/29/19

STATE OF CALIFORNIA )

)ss.

COUNTY OF __________________)

The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of M-S-R Public Power Agency, a California joint powers agency, on behalf of said joint powers agency.

Notary Public

My commission expires:

174 Restructuring Amendment 7/31/2015

CALIFORNIA ALL-PURPOSE ACKNOWLEDGMENT CIVIL CODE § 1189

A notary public or other officer completing this certificate verifies only the identity of the individual who signed the document to which this certificate is attached, and not the truthfulness, accuracy, or validity of that document.

State of California )

County of ____ Amador ___________________)

On __ July 27, 2015 _________before me, _________ Lynn V. Verhagen, Notary Public ______________ , Date Here Insert Name and Title of the Officer

personally appeared _______ Martin R. Hopper ______________________________________________

Name(s) of Signer(s)

____________________________________________________________________________________

who proved to me on the basis of satisfactory evidence to be the person( s ) whose name( s ) is/are

subscribed to the within instrument and acknowledged to me that he /she/they executed the same in

his /her/their authorized capacity( ies ), and that by his/ her/their signature( s ) on the instrument the person( s ),

or the entity upon behalf of which the person( s ) acted, executed the instrument.

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

Signature_ /s/ Lynn V. Verhagen _________

Signature of Notary Public

Place Notary Seal Above

-----------------------------------------------------------------OPTIONAL----------------------------------------------------------

Though this section is optional, completing this information can deter alteration of the document or

fraudulent reattachment of this form to an unintended document.

Description of Attached Document

Title or Type of Document:___ Restructuring Agreement _________ Document Date: ___ 7/27/15 ______

Number of Pages: ___ 177 ____ Signer(s) Other Than Named Above:

______________________________Capacity(ies) Claimed by Signer(s)



□Signer's Name:_____________________	□Signer's Name:_____________________
□Corporate Officer ___ Title(s):_________	□Corporate Officer ___ Title(s):_________
□Partner - □Limited □General	□Partner - □Limited □General
□Individual □Attorney in Fact	□Individual □Attorney in Fact
□Trustee □Guardian or Conservator	□Trustee □Guardian or Conservator
□Other: ____________________________	□Other: ____________________________
Signer Is Representing: _______________	Signer Is Representing: _______________
__________________________________	__________________________________

STATE OF NEW MEXICO )

)ss.

COUNTY OF LOS ALAMOS )

The foregoing instrument was acknowledged before me on this _ 28th __ day of July, 2015, by _ ___Kristin Henderson _______, ____ Council Chair ___________ of The Incorporated County of Los Alamos, New Mexico, a New Mexico Class H County, on behalf of said county.

/s/ Melissa A. Salmon

Notary Public

My commission expires:

__January 07, 2018

STATE OF CALIFORNIA )

)ss.

COUNTY OF ________________ )

The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Southern California Public Power Authority, a California joint powers agency, on behalf of said joint powers agency.

Notary Public

My commission expires:

175 Restructuring Amendment 7/31/2015

CALIFORNIA ALL-PURPOSE ACKNOWLEDGMENT

CIVIL CODE § 1189

State of California )

County of ____ Los Angeles ___________________)

On __ July 16, 2015 _________before me, _________ Salpi Ortiz, a notary public ________________ ,

Date Here Insert Name and Title of the Officer

personally appeared _______ Fred Mason ___________________________________

Name(s) of Signer(s)

____________________________________________________________________________________

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

Signature_ /s/ Salpi Ortiz _________

Signature of Notary Public

Place Notary Seal Above

-----------------------------------------------------------------OPTIONAL----------------------------------------------------------

Though this section is optional, completing this information can deter alteration of the document or fraudulent reattachment of this form to an unintended document.

Description of Attached Document

Title or Type of Document:_________________________ Document Date: ___ ______ ______

Number of Pages: _______ Signer(s) Other Than Named Above: ______________________________

Capacity(ies) Claimed by Signer(s)



□Signer's Name:_____________________	□Signer's Name:_____________________
□Corporate Officer ___ Title(s):_________	□Corporate Officer ___ Title(s):_________
□Partner - □Limited □General	□Partner - □Limited □General
□Individual □Attorney in Fact	□Individual □Attorney in Fact
□Trustee □Guardian or Conservator	□Trustee □Guardian or Conservator
□Other: ____________________________	□Other: ____________________________
Signer Is Representing: _______________	Signer Is Representing: _______________
__________________________________	__________________________________

CALIFORNIA ALL-PURPOSE ACKNOWLEGEMENT CIVIL CODE #1189

STATE OF CALIFORNIA )

)ss.

COUNTY OF ORANGE )

On July 27, 2015 before me, Annie DeSouza , Notary Public, personally

Appeared _ DUKKU LEE_ who proved to me on the basis of satisfactory evidence to be the person(s) whose name( s ) is/ are subscribed to the within instrument and acknowledged to me that he/ she/they executed the same in his/ her/their authorized capacity( ies ), and that by his/ her/their signature( s ) on the instrument the person( s ), or the entity upon behalf of which the person( s ) acted, executed the instrument.

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

___/s/ Annie DeSouza___

[SEAL]

STATE OF CALIFORNIA )

)ss.

COUNTY OF ORANGE )

The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of the City of Anaheim, a California municipal corporation, on behalf of the said municipal corporation.

Notary Public

My commission expires:

STATE OF UTAH )

)ss.

COUNTY OF SALT LAKE )

The foregoing instrument was acknowledged before me on this _ 30th_ day of July, 2015, by _ Douglas Hunter _________, __ General Manager _________ of Utah Associated Municipal Power Systems, a political subdivision of the State of Utah, on behalf of said entity.

/s/ Andrea Miller

Notary Public

My commission expires:

June 15, 2019

176 Restructuring Amendment 7/31/2015

STATE OF COLORADO )

)ss.

COUNTY OF ADAMS )

The foregoing instrument was acknowledged before me on this _ 22 ___ day of July, 2015, by __ _Micheal S. McInnes _____, _ CEO___ _________________ of Tri-State Generation and Transmission Association, Inc., a Colorado cooperative corporation, on behalf of the said cooperative corporation.

/s/ Penny L. McLaughlin

Notary Public

My commission expires:

September 11, 2018

STATE OF NEW MEXICO )

)ss.

COUNTY OF BERNALILLO )

The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of PNMR Development and Management Corporation, a New Mexico corporation, on behalf of the corporation.

Notary Public

My commission expires:

177 Restructuring Amendment 7/31/2015

STATE OF COLORADO )

)ss.

COUNTY OF ADAMS )

The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Tri-State Generation and Transmission Association, Inc., a Colorado cooperative corporation, on behalf of the said cooperative corporation.

Notary Public

My commission expires:

STATE OF NEW MEXICO )

)ss.

COUNTY OF BERNALILLO )

The foregoing instrument was acknowledged before me on this _ 30th _ day of _ June _, 2015, by ___ Elisabeth Eden ____, ____ President, CEO and Treasurer __ of PNMR Development and Management Corporation, a New Mexico corporation, on behalf of the corporation.

/s/ Marcella Kercher

Notary Public

My commission expires:

12/19/2015

Restructuring Amendment 7/31/2015

REFERENCES TO EXHIBITS IN

PARTICIPATION AGREEMENT

Exhibit No . References in Agreement Subject Matter

I §§ 2.10, 6.1 Real Property

II § 5.24 Annual Minimum Coal

III §§ 5.44, 6.5 Switchyard Facilities

IV §§ 6.2, 6.2.8 Ownership of Equipment

V §§ 22.1.7, 22.1.9 O&M of Equipment

VI §§ 7.11, 22.2.2, 22.6, 22.6.1, 22.7, 22.8

A&G Expenses

VII § 23.3 Coal Allocation and Billing

VIII §§ 18.4, 19.4, 20.5, 21.4 Adjustment of Voting

IX §§ 5.19, 23.4.1, 23.4.1.3 Fixed Fuel Expense

X §§ 5.55, 23.4.1, 23.4.1.3 Variable Fuel Expense

EXHIBIT I

This Exhibit I to the Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement contains a map of the San Juan Project Generating Station site and the River Weir site, showing Parcels A, B, C, C-1 D, E and F, the parcels of real property underlying the San Juan Project and River Weir sites. Also included in the Exhibit are property descriptions and separate maps showing Parcels A through F. PNM and TEP each has a one-half undivided ownership interest in the parcels described as Parcels A, B, C, D, E and F; and PNM and TEP each has a one-half leasehold interest in Parcel C-1.

Exh. I - 1

PARCEL A

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 16: SW 1/4

Section 20: NE 1/4, N 1/2 SE 1/4, SW 1/4SE 1/4

Section 21: NW 1/4 NW 1/4

Section 29: NE 1/4

PARCEL B

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SW 1/4, SW 1/4 SE 1/4

Section 20: E 1/2 NW 1/4, NE 1/4 SW 1/4

Section 29: NW 1/4, N 1/2 SW 1/4

Section 30: NE 1/4, E 1/2 NW 1/4, N 1/2 SE 1/4

PARCEL C

That part of Lot 6 in Section 4 and of Lot 5 in Section 3, Township 29 North, Range 15 West, N.M.P.M., San Juan County, New Mexico, described as follows:

Beginning at a point which is 772.69 feet, South 88º12’03” East from Northwest Corner of Lot 6:

Thence, S. 55º50’29” E., 205.55 feet; thence, N. 78º21’34” E., 457.06 feet; thence N. 88º29’07” E., 746.61 feet; thence, S. 25º38’00” W., 1,177.50 feet; thence, N. 54º32’00” W., 1,291.70 feet; thence, N. 32º1’00” E., 372.20 feet to the point of beginning. Containing 21.039 acres, more or less.

PARCEL C-1

A tract of land situated adjacent to the southerly side of the San Juan River in Sections 3, 4, 9 and 10, Township 29 North, Range 15 West, N.M.P.M., San Juan County, New Mexico, and more particularly described as follows:

Exh. I - 2

Beginning at point A, from which the corner common to Sections 33 and 34, T.30 N., R. 15 W., and Sections 4 and 3, T. 29 N., R 15 W., bears N. 06º09’45” E., 4,966.7 feet; thence N. 49º00’00” E., 351.95 feet to point B located on the approximate centerline of the San Juan River; thence along the centerline of the River S. 50º44’26” E., 268.63 feet to point C; thence continuing along the centerline of the River, S. 41º18’31” E., 263.59 feet to point D; thence S. 21º12’40” E., 678 feet to point E; thence S. 51º00’00” W., 209 feet to point F; thence N. 39º00’00” W., 1,160.00 feet to the point of beginning; containing 9.376 acres, more or less.

PARCEL D

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 17: SE 1/4 SW 1/4, S1/2 SE 1/4

PARCEL E

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SE 1/4

NE 1/4 SE 1/4

E 1/2 NW 1/4 SE 1/4

S 1/2 S 1/2 SE 1/4 NE 1/4

Section 20: SE 1/4 SW 1/4

SW 1/4 SW 1/4

NW 1/4 SW 1/4

S 1/2 SW 1/4 SW 1/4 NW 1/4

Containing 235 acres, more or less.

PARCEL F

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 20: SE 1/4 SE 1/4

Exh. I - 3

Exh. I - 4

Exh. I - 5

Exh. I - 6

Exh. I - 7

Exh. I - 8

Exh. I - 9

Exh. I - 10

EXHIBIT II

EXHIBIT H TO UNDERGROUND COAL SALES AGREEMENT

SAN JUAN STATION MINIMUM DELIVERIES2003-2017



Column 1	Column 2	Column 3
Year	Minimum Annual Tons	Annual Processing Tons
2003	5,600,000	5,480,500
2004	5,600,000	5,480,500
2005	5,600,000	5,126,000
2006	5,600,000	5,126,000
2007	5,600,000	5,126,000
2008	5,600,000	5,118,000
2009	5,600,000	4,810,000
2010	5,600,000	4,810,000
2011	5,600,000	4,810,000
2012	5,600,000	4,810,000
2013	5,600,000	4,500,000
2014	5,600,000	4,500,000
2015	5,600,000	3,860,000
2016	5,600,000	3,860,000
2017	5,600,000	1,086,500
	84,000,000	68,503,500

Note: The UG-CSA will be terminated upon the effective date of this Agreement.

Exh. II - 1

EXHIBIT III

SAN JUAN PROJECT SWITCHYARD FACILITIES

Material List



Phase I – Project (DWG, ED-54, ED-55)
QUANTITY	DESCRIPTION
5	345 kV Circuit Breakers – (G.E. A.T.B.’s)
16	345 kV Motor Operated Disconnect Switches with Stands

2	345 kV S&C Circuit Switches with Stands
Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
4	Line Deadend Towers
5	Intermediate Bus Towers
1	Start-Up Transformers 345/12.47/4.16 kV, 24/32/40 MVA
1	Set of 4.16 kV Switchgear
1	4.16 kV Start-Up Cable Run into Plant
2	4.16 kV Station Service Transformers
1	Set of 12.45 kV Switchgear
3	12.47 kV Zig-Zag Grounding Transformer
6	345 kV PCM Potential Transformers with Stands (Bus #1, Bus #2)
6	345 kV Bus Lightning Arresters with Stands

1	Control House 40’ x 72’
2	Sets of Batteries & Chargers, 125 v and 48 v
1	Microwave Tower
Lot	Cable Troughs, Equipment Controls, Breaker Failure Relaying, Fault Recorder
Lot	Metering – Indication, Billing and Telemetry Transducers
Lot	Switchyard Foundations, Fencing, Grading, Grounding

1	Line Trap (FC Line)
1	345 kV PCM Potential Transformer/Coupling Capacitor with Stand
3	345 kV Line Lightning Arresters with Stands
Lot	Line Relaying, Carrier, Microwave
1	345-69-12470 Transformer
1	345/230-12470 Transformer, 230 yard
1	Reactor – 12.47 kV, 345 yard

Exh. III - 1



Phase 2 – Project (DWG. SK-135)
QUANTITY	DESCRIPTION
4	345 kV Circuit Breakers
3	345 kV Motor Operated Disconnect Switches with Stands

Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
1	Intermediate Bus Tower
Lot	Cable Troughs, Equipment Controls, Breaker Failure Relaying
Lot	Metering – Indication, Billing and Telemetry Transducers
Lot	Switchyard Foundations, Grounding

Phase 3 – Project (DWG. SK-316)
3	345 kV Circuit Breakers
6	345 kV Motor Operated Disconnect Switches with Stands
Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
1	Line Deadend Tower
2	Intermediate Bus Towers
Lot	Cable Troughs, Equipment Controls, Breaker Failure Relaying
Lot	Metering – Indication, Billing and Telemetry Transducers
Lot	Switchyard Foundations and Grounding

Phase 3 – Project (DWG. SK-317)
2	345 kV Circuit Breakers
4	345 kV Motor Operated Disconnect Switches with Stands
Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
1	Intermediate Bus Tower
Lot	Switchyard Foundations, Grounding

Exh. III - 2

EXHIBIT IV

EXHIBIT IV(a)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 1

Ownership



PNM -	50	%	TEP -	50	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	0	%	LAC-	0	%
SCPPA -	0	%	Anaheim -	0	%
PNMR-D	0	%	UAMPS -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment.)


12.	Fly Ash System

Exh. IV - 1

EXHIBIT IV(a)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	SSR Protection System


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. IV - 2

EXHIBIT IV(b)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 2

Ownership



PNM -	50	%	TEP -	50	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	0	%	LAC -	0	%
SCPPA -	0	%	Anaheim -	0	%
PNMR-D -	0	%	UAMPS -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment.)


12.	Fly Ash System

Exh. IV - 3

EXHIBIT IV(b)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. IV - 4

EXHIBIT IV(c)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 3

Ownership



PNM -	50	%	TEP -	0	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	8.2	%	LAC -	0	%
SCPPA -	41.8	%	Anaheim -	0	%
PNMR-D	0	%	UAMPS -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 3A and 3B Transformers*


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, Storage Tank, and Pump House


12.	Fly Ash System

Exh. IV - 5

EXHIBIT IV(c)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	Coal Reclaim Hoppers, Feeders, Feeder Belts, Belt Scales, Fire Protection System, and 3C Conveyor to the Secondary Crusher Building


20.	SSR Protection System


21.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant


*	PNM and TEP each owns a 50% interest in the main unit transformer

Exh. IV - 6

EXHIBIT IV(d)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 4

Ownership



PNM -	38.457	%	TEP -	0	%
M-S-R -	28.8	%	Farmington -	8.475	%
Tri-State -	0	%	LAC -	7.2	%
SCPPA -	0	%	Anaheim -	10.04	%
PNMR-D	0	%	UAMPS -	7.028	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 4A and 4B Transformers


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, Storage Tank, and Pump House


12.	Fly Ash System

Exh. IV - 7

EXHIBIT IV(d)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	Coal Reclaim Hoppers, Feeders, Feeder Belts, Belt Scales, Fire Protection System, and 3D Conveyor to the Secondary Crusher Building


20.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant

Exh. IV - 8

EXHIBIT IV(e)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNITS NO. 1 AND 2

Ownership



PNM -	50	%	TEP -	50	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	0	%	LAC -	0	%
SCPPA -	0	%	Anaheim -	0	%
PNMR-D	0	%	UAMPS -	0	%


1.	Bearing Cooling Water System


2.	Bottom Ash Dewatering Facility including: Dewatering Tank, Settling Tank, Surge Tank, Storage Tank, and Pump House


3.	Demineralizer System including: Clarifier, Storage Tanks, and Sump Pump


4.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization)


5.	Premix Tank Facility (This was the wastewater neutralizer facility and is now operated as part of the Water Management System.)


6.	Instrument Air system, except Unit Piping


7.	Chemical Feed System, except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System


8.	Plant Air System, except Unit Piping


9.	Sootblowing Air System, except Unit Piping


10.	Hydrogen Storage System, except Unit Piping

Exh. IV - 9

EXHIBIT IV(e)

(continued)


11.	Coal Handling Reclaim Systems A and B including: Hoppers, Feeders, Reclaim Conveyors, Belt Scales, and Sprinkler System


12.	Coal Tripper System south of column, Line 12 including Dust Collection System


13.	Turbine Lube Oil Storage and Transfer System


14.	Control Room, Equipment Rooms, and Associated HVAC System


15.	Turbine Crane south of column, Line 12


16.	Fuel Oil, Ash, and Water Pipe Racks


17.	Boiler Fill System for Units 1 and 2


18.	All spare parts common to either unit


19.	SO2 Backup Scrubber-Absorber Transformer


20.	SAR Multiplexer Control System

Exh. IV - 10

EXHIBIT IV(f)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNITS NO. 3 AND 4

Ownership



PNM -	44.119	%	TEP -	0	%
M-S-R -	14.4	%	Farmington -	4.249	%
Tri-State -	4.1	%	LAC -	3.612	%
SCPPA -	20.9	%	Anaheim -	5.07	%
PNMR-D	0	%	UAMPS -	3.55	%

1. Bearing Cooling Water System

2. Demineralizer System: including Sump Pumps, Filter Beds, and Storage Tanks


3.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization except Ignitor Heaters and Unit Specific Piping)


4.	Wastewater Neutralizer Facility (This facility is operated as part of Water Management System.)

5. Instrument Air System except Unit Piping

6. Chemical Feed System except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System

7. Plant Air System except Unit Piping

8. Sootblowing Air System except Unit Piping

9. Start-Up Transformers and Nonseg Bus to Units 3 and 4 Switchgear

10. Hydrogen Storage System except Unit Piping

11. Coal Tripper System Serving Units 3 and 4 including Dust Collection Systems

Exh. IV - 11

EXHIBIT IV(f)

(continued)

12. Turbine Lube Oil Storage and Transfer System

13. Control Room, Equipment Rooms, and Associated HVAC System

14. Boiler Fill System for Units 3 and 4


15.	Auxiliary Cooling Systems including Auxiliary Cooling Tower No. 1 and Pumps, but excepting No. 4 Tower Pumps and Piping which is Unit Specific

16. CO2 Storage System

17. Start-Up Boiler Feed Pump

18. Turbine Bay Crane north of column, Line 12

19. Fuel Oil, Ash, and Water Pipe Racks

20. Fire Water Booster and Jockey Pumps

21. Halon Fire Protection System

22. Cooling Tower Multiplex Control System

23. All spare parts common to either unit

Exh. IV - 12

EXHIBIT IV(g)

FACILITIES AND EQUIPMENT

COMMON TO ALL FOUR SAN JUAN UNITS

Ownership



PNM -	46.29	%	TEP -	19.8	%
M-S-R -	8.7	%	Farmington -	2.559	%
Tri-State -	2.49	%	LAC -	2.175	%
SCPPA -	12.71	%	Anaheim -	3.10	%
PNMR-D	0	%	UAMPS -	2.169	%


1.	River and Raw Water System including:


a.	Diversion and intake structures, including all equipment and pump building.


b.	Raw Water line to reservoir.


c.	Reservoir, pump buildings, and all equipment.


d.	Raw water lines to plant yard.


e.	All above and underground fire protection system to each vendor supplied or unit specific fire protection system.

2. Auxiliary Boiler

3. SO2 Removal System except Absorbers

NOTE: The new SO2 Absorber Feed System is being placed in-service to replace the SO2 Chemical Plant previously used by the Project. The SO2 Chemical Plant facilities will be retired in place and will be salvaged or decommissioned at a later date. Section 3.1 describes the new SO2 Absorber Feed System while Section 3.2 describes the old SO2 Chemical Plant.

3.1 SO2 Absorber Feed System


a.	Limestone Handling System


b.	Limestone Preparation System


c.	Dewatering System


d.	Gypsum Stack Out System

Exh. IV - 13

EXHIBIT IV(g)

(continued)

3.2 SO2 Chemical Plant


a.	Double effect evaporator train systems.


b.	Fly ash filter system.


c.	Absorber product and feed tanks.


d.	Condensate collection, storage, and transfer systems.


e.	Soda ash storage, mixing, and distribution systems.


f.	Sulfate purge system including: crystallizers, centrifuges, evaporators, and salt cake system.


g.	Sulfuric acid plant system including storage tanks and load out system.


h.	Auxiliary. No. 2 cooling tower, pumps, and systems.

4. Spare-Main Transformer 345/24 kV for all units.

5. Maintenance, Office, and Warehousing Facilities

6. Chemical Laboratory

7. Coal and Ash Handling Control Facilities

8. Roads and grounds such as fencing, yard lighting, guard facilities, drainage, and dikes.

9. Potable Water System


10.	Environmental Monitoring systems including Air, Water, and Ground. Excludes Stack Monitoring Systems which are unit specific.

11. Transportation such as trucks, cars, and dozers (not otherwise charged).

12. Water Management System


a.	Wastewater Recovery System -- Northside


1.	Reverse osmosis system including lime/soda softening clarifier system.


2.	Brine concentrator Nos. 4 and 5.


3.	Process pond No. 3 and pump system


4.	North evaporation ponds 1, 2, and 3.

Exh. IV - 14

EXHIBIT IV(g)

(continued)


b.	SO2 Waste Treatment System -- Southside


1.	Process ponds 1A, 1 B, 2 and pumping system.


2.	Premix tank and clarifier system.


3.	Oxidation towers.


4.	Brine concentrator Nos. 2 and 3.


5.	South evaporation ponds Nos. 1, 2, 3, 4, and 5.


c.	Data Acquisition System


d.	Solid Waste Disposal Pit


e.	Coal pile runoff pond


13.	Coal Transfer Facilities from the Reclaim Conveyors to the Head-End of Plat Belts 4A and 4B and Dust Suppression Systems


14.	Maintenance Bay Facilities including: Bay Bridge Crane, all Offices, and Support Facilities

15. Sewage Treatment Facilities


16.	On each of Units 1 and 2, the Chemical Plant 165-pound Control Valve, and Branch Line from the Unit Specific 650-pound Rehear Steam Line


17.	On each of Units 3 and 4, the Chemical Plant Branch Steam Line from the Unit Specific Auxiliary Steam Header System

Exh. IV - 15

EXHIBIT IV(h)

SAN JUAN PROJECT

SWITCHYARD FACILITIES

Cost Allocation (%)



	Installed Cost		Replacements/Improvements Betterments
	PNM	TEP	PNM	TEP
345 kV Bus 1 & 3 (East Bus)	50	50	50	50
Bus 2 (West Bus)	50	50	50	50
Circuit Breakers
06582 (345/230)	50	50	50	50
5482	50	50	50	50
04382 (OJO)	50	50	50	50
12982 (McKinley)	50	50	50	50
11882	50	50	50	50
10782 (Unit 4)	50	50	50	50
09882 (McKinley)	58.33	41.67	62.5	37.5
8782	54.16	45.84	56.25	43.75
07682 (Unit 3)	50	50	50	50

15282 (Four Comers)	50	50	50	50
14182	50	50	50	50
13082 (Unit 2)	50	50	50	50

18582 (West Mesa)	50	50	50	50
17482	50	50	50	50
16382 (Unit 1)	50	50	50	50
20782	50	50	50	50

Shunt Reactors
Ojo	100	0	100	0
McKinley 1	5.36	94.64	5.36	94.64
McKinley 2	16.67	83.33	25	75
WW (BA)	100	0	100	0

Exh. IV - 16

EXHIBIT IV(h)

(continued)



	Installed Cost		Replacements/Improvements Betterments
	PNM	TEP	PNM	TEP
Transformers
Station Aux. No. 2 400 MVA, 345/230-12.5	100	0	100	0
Station Aux. No. 1 345/4.16-12.5	50	50	50	50
Station Aux. No. 3 90 MVA, 345/69-12.5	50	50	50	50

Future Facilities 345/69/12 kV	66.67	33.33	66.67	33.33
2-345 kV Bkrs (Durango)	50	50	50	50

Lower Voltage 230 kV Control Hse	83.33	16.67	83.33	16.67
230/69 kV Trf	66.67	33.33	66.67	33.33
Shiprock 230 kV line	100	0	100	0

Exh. IV - 17

EXHIBIT V

EXHIBIT V(a)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 1

Operation and Maintenance Costs



PNM -	50	%	TEP -	50	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	0	%	LAC -	0	%
SCPPA -	0	%	Anaheim -	0	%
PNMR-D	0	%	UAMPS -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment)


12.	Fly Ash System

Exh. V - 1

EXHIBIT V(a)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	SSR Protection System


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. V - 2

EXHIBIT V(b)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 2

Operation and Maintenance Costs



PNM -	50	%	TEP -	50	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	0	%	LAC -	0	%
SCPPA -	0	%	Anaheim -	0	%
PNMR-D	0	%	UAMPS -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment)


12.	Fly Ash System

Exh. V - 3

EXHIBIT V(b)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. V - 4

EXHIBIT V(c)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 3

Operation and Maintenance Costs



PNM -	50	%	TEP -	0	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	8.2	%	LAC -	0	%
SCPPA -	41.8	%	Anaheim -	0	%
PNMR-D	0	%	UAMPS -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 3A and 3B Transformers


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, and Pump House


12.	Fly Ash System

Exh. V - 5

EXHIBIT V(c)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the Reheat Steam Line from the Auxiliary Steam Header


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	SSR Protection System


20.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant

Exh. V - 6

EXHIBIT V(d)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 4

Operation and Maintenance Costs



PNM -	38.457	%	TEP -	0	%
M-S-R -	28.8	%	Farmington -	8.475	%
Tri-State -	0	%	LAC -	7.2	%
SCPPA -	0	%	Anaheim -	10.04	%
PNMR-D	0	%	UAMPS -	7.028	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 4A and 4B Transformers


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, and Pump House


12.	Fly Ash System

Exh. V - 7

EXHIBIT V(d)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the Reheat Steam Line from the Auxiliary Steam Header


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant

Exh. V - 8

EXHIBIT V(e)

FACILITIES AND EQUIPMENT

COMMON TO SAN JUAN UNITS NO. 1 AND 2

Operation and Maintenance Costs



PNM -	50	%	TEP -	50	%
M-S-R -	0	%	Farmington -	0	%
Tri-State -	0	%	LAC -	0	%
SCPPA -	0	%	Anaheim -	0	%
PNMR-D	0	%	UAMPS -	0	%


1.	Bearing Cooling Water System except Unit Piping


2.	Bottom Ash Dewatering Facility including: Dewatering Tank, Settling Tank, Surge Tank, Storage Tank, and Pump House


3.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization)


4.	Instrument Air System, except Unit Piping


5.	Chemical Feed System, except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System


6.	Plant Air System, except Unit Piping


7.	Sootblowing Air System, except Unit Piping


8.	Hydrogen Storage System, except Unit Piping


9.	Coal Tripper System including Dust Collection System


10.	Turbine Lube Oil Storage and Transfer System


11.	Control Room, Equipment Rooms, and Associated HVAC System

Exh. V - 9

EXHIBIT V(e)

(continued)


12.	SO2 Backup Scrubber-Absorber Transformer


13.	Turbine Crane south of column, Line 12


14.	Fuel Oil, Ash, and Water Pipe Racks


15.	Boiler Fill System


16.	SAR Multiplexer Control System

Exh. V - 10

EXHIBIT V(f)

FACILITIES AND EQUIPMENT

COMMON TO SAN JUAN UNITS NO. 3 AND 4

Operation and Maintenance Costs



PNM -	44.119	%	TEP -	0	%
M-S-R -	14.4	%	Farmington -	4.249	%
Tri-State -	4.1	%	LAC-	3.612	%
SCPPA -	20.9	%	Anaheim -	5.07	%
PNMR-D	0	%	UAMPS -	3.55	%

1. Bearing Cooling Water System except Unit Piping


2.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization except Ignitor Heaters and Unit Specific Piping)

3. Instrument Air System except Unit Piping

4. Chemical Feed System except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System

5. Plant Air System except Unit Piping

6. Sootblowing Air System except Unit Piping

7. Start-Up Transformers and Nonseg Bus to Units 3 and 4 Switchgear

8. Hydrogen Storage System except Unit Piping

9. Coal Tripper System including Dust Collection Systems

10. Turbine Lube Oil Storage and Transfer System

11. Control Room, Equipment Rooms, and Associated HVAC System

Exh. V - 11

EXHIBIT V(f)

(continued)

12. Boiler Fill System


13.	Auxiliary Cooling Systems including Auxiliary Cooling Tower No. 1 and Pumps, but excepting No. 4 Tower Pumps and Piping which is Unit Specific

14. CO2 Storage System except Unit Piping

15. Start-Up Boiler Feed Pump except Unit Piping

16. Turbine Bay Crane north of column, Line 12

17. Fuel Oil, Ash, and Water Pipe Racks

18. Fire Water Booster and Jockey Pumps

19. Halon Fire Protection System

20. Cooling Tower Multiplex Control System

Exh. V - 12

EXHIBIT V(g)

FACILITIES AND EQUIPMENT

COMMON TO ALL FOUR SAN JUAN UNITS

Operation and Maintenance Costs



PNM -	46.297	%	TEP -	19.8	%
M-S-R -	8.7	%	Farmington -	2.559	%
Tri-State -	2.49	%	LAC -	2.175	%
SCPPA -	12.71	%	Anaheim -	3.10	%
PNMR-D	0	%	UAMPS -	2.169	%


1.	River and Raw Water System including:


a.	Diversion and intake structures, including all equipment and pump building.


b.	Raw Water line to reservoir.


c.	Reservoir, pump buildings, and all equipment.


d.	Raw water lines to plant yard.


e.	All above and underground fire protection system to each vendor supplied or unit specific fire protection system.

2. Auxiliary Boiler

3. SO2 Removal System except Absorbers

NOTE: In April 1998 the new SO2 Absorber Feed System went in-service and replaced the SO2 Chemical Plant previously used by the Project. The SO2 Chemical Plant facilities are retired in place and will be salvaged or decommissioned at a later date. Section 3.1 describes the new SO2 Absorber Feed System while Section 3.2 describes the old SO2 Chemical Plant.

3.1 SO2 Absorber Feed System


a.	Limestone Handling System


b.	Limestone Preparation System


c.	Dewatering System


d.	Gypsum Stack Out System

Exh. V - 13

EXHIBIT V(g)

(continued)

3.2 SO2 Chemical Plant

a. Double effect evaporator train systems.

b. Fly ash filter system.

c. Absorber product and feed tanks.

d. Condensate collection, storage, and transfer systems.

e. Soda ash storage, mixing, and distribution systems.


f.	Sulfate purge system including: crystallizers, centrifuges, evaporators, and salt cake system.

g. Sulfuric acid plant system including storage tanks and load out system.

h. Auxiliary No. 2 cooling tower, pumps, and systems.

4. Spare-Main Transformer 345/24 kV for all units.

5. Maintenance, Office, and Warehousing Facilities

6. Chemical Laboratory

7.* Coal and Ash Handling Control Facilities

8. Roads and grounds such as fencing, yard lighting, guard facilities, drainage, and dikes.

9. Potable Water System


10.	Environmental Monitoring systems including Air, Water, and Ground. Excludes Stack Monitoring Systems which are unit specific.

11. Transportation such as trucks, cars, and dozers (not otherwise charged).

12. Water Management System


a.	Wastewater Recovery System -- Northside


1.	Neutralization system including premix tank, neutralization tank, clarifier/thickener, and pumps.


2.	Reverse osmosis system including lime/soda softening clarifier system.


3.	Brine concentrator Nos. 4 and 5.


4.	Process pond No. 3 and pump system.


5.	North evaporation ponds 1, 2, and 3.

Exh. V - 14

EXHIBIT V(g)

(continued)


b.	SO2 Waste Treatment System -- Southside


1.	Process ponds 1A, 1B, 2 and pumping system.


2.	Premix tank and clarifier system.


3.	Oxidation towers.


4.	Brine concentrator Nos. 2 and 3.


5.	South evaporation ponds Nos. 1, 2, 3, 4, and 5.


c.	Data Acquisition System


d.	Solid Waste Disposal Pit


e.	Coal pile runoff pond


13.*	Coal Handling Equipment -- all equipment from all reclaim hoppers ending at the chutes to the tripper conveyors. This includes: hoppers. feeders. feeder belts, reclaim conveyors, plant conveyors, belt scales, fire protection systems, dust suppression systems, magnetic separators, all electrical and controls, and heating and ventilation systems.


14.	Maintenance Bay Facilities including: Bay Bridge Crane, all Offices, and Support Facilities

15. Sewage Treatment Facilities


16.	All Demineralizer Systems including: Clarifier, Storage Tanks, Sump Pumps, Filter Beds, and Control Systems.


17.	The Chemical Plant 165-pound Control Valve and Branch Line from each of Units 1 and 2 Unit Specific 650-pound Reheat Steam Line.


18.	The Chemical Plant Branch Steam Line from (but not including) the Unit Specific Auxiliary, Steam Header System on each of Units 3 and 4.

*Maintenance Only

Exh. V - 15

EXHIBIT V(h)

FACILITIES AND EQUIPMENT

COMMON TO ALL FOUR SAN JUAN UNITS

Operation Costs Only



PNM
M-S-R
TEP	Variable split based on generation by unit
Farmington
Tri-State
LAC
SCPPA
Anaheim
UAMPS PNMR-D

1. Coal and Ash Handling Control Facilities

2. Coal Handling Equipment

All equipment from all reclaim hoppers ending at the chutes to the tripper conveyors. This includes: hoppers, feeders, feeder belts, reclaim conveyors, plant conveyors, belt scales, fire protection systems, dust suppression systems, magnetic separators, all electrical and control, and heating and ventilation systems.

Exh. V - 16

EXHIBIT V(i)

SWITCHYARD FACILITIES AND EQUIPMENT

OPERATION AND MAINTENANCE COSTS



PNM - 65%	TEP - 35%

Exh. V - 17

EXHIBIT VI

San Juan Operating Agreement

Exhibit VI-Attachment A

A&G RATIO APPLICABLE TO OPERATION AND MAINTENANCE FOR THE SAN JUAN GENERATING STATION (“SJGS”)

The Operating Agent determines, in accordance with Accounting Practice, the appropriate A&G expense incurred for the benefit of the SJGS and to be billed to the SJGS as follows:

1. A&G expenses directly chargeable by on-site San Juan Project employees as set forth in Section 22.2.2;

2. A&G expenses directly chargeable by A&G related departments located off-site as set forth in Section 22.2.2; and

3. Indirect A&G expenses included in the development of the A&G ratio.

Except as set forth in Section 22.0, individuals located off-site must either charge their time and expenses direct to the SJGS or be included in the A&G pool in the development of the A&G Ratio. Costs incurred for the same purpose must be either all charged direct to the SJGS or all be included in the A&G pool, e.g., all staff persons within the same department must either charge direct to the SJGS or to the A&G pool.

The Operating Agent conducts an A&G study every three years. However, periodic reviews will be performed to determine if significant organizational changes have occurred that may require the Operating Agent to conduct an A&G study on a basis more frequently than three years. This study determines the appropriate amount of indirect A&G expense to utilize in the development of the A&G Ratio described below.

The FERC A&G accounts included in the A&G study are: 920, 921, 923, 930.2, 931 and 935.

Background

The responsibility for the SJGS resides in the Operating Agent’s Bulk Power Business Unit. The A&G expenses charged to this Business Unit are derived from two areas. The first component is an allocation of A&G expenses from the Operating Agent’s Corporate Office to the Bulk Power Business Unit. These allocations are based on pre-determined methodologies. The second component of costs are A&G expenses that are directly charged to the Bulk Power Business Unit. Note: Any A&G expenses charged directly to the SJGS are excluded from the determination of the A&G Ratio and are not subject to the A&G Ratio.

Exh. VI-1

A questionnaire is sent to all managers that have A&G charges to the Bulk Power Business Unit to determine what percentage of their A&G expenses should be included in the development of the A&G Ratio.

The percentages derived from the questionnaires are then applied to the actual A&G amounts charged to the Bulk Power Business Unit for the study year. Amounts are split between labor and other.


B.	Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) (See Exhibit VI Attachments B, C and D) are applied to the labor portion of the A&G determined above.


C.	Other costs included in the development of the A&G Ratio are Depreciation of General Plant (FERC Account 403), Property Insurance (FERC Account 924) and Property Taxes (FERC Account 408) for the Operating Agent’s headquarters buildings and energy management facility and Amortization of Computer Software (FERC Account 404) for certain software applications that provide benefit to the SJGS.

The portion of the costs related to the Operating Agent’s headquarters buildings included in the development of the A&G Ratio are derived by applying certain ratios obtained from the A&G study questionnaires. The costs included in the A&G Ratio for the Operating Agent’s energy management facility are based on the number of MW of SJGS capacity as a percentage of the Operating Agent’s total generating capacity. In addition, ratios for determining the amount of software costs to include in the A&G Ratio are based on the specific software application. For example, if the Operating Agent installed a new payroll system, the amount of costs for this system that would be included in the A&G Ratio calculation would be based on the number of employees at the SJGS as a percent of the Operating Agent’s total employees. The Operating Agent reviews each specific software application to determine the method for assigning the appropriate amount of costs to be included in the A&G Ratio calculation.

The A&G ratio shall be applied to the following SJGS costs:


1)	Labor charged to the operation and maintenance expenses included in Sections 22.2.1, 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement. Such labor dollars are utilized as the denominator in the calculation of the A&G Ratio described below.

The A&G Ratio shall be derived annually based on the preceding year’s experience, as set forth herein unless otherwise agreed to by the participants. The A&G Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the A&G Ratio for the following year.

A&G Ratio = A/B

Exh. VI - 2

Where A = Administrative and general expense chargeable to FERC Accounts 920, 921,

923, 930.2, 931 and 935, including Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) plus other related costs for the Operating Agent’s headquarters buildings and energy management facility for Property Taxes FERC Account (408), Depreciation of General Plant FERC Account (403), and Property Insurance FERC Account (924) plus amortization of certain Computer Software costs charged to FERC Account (404).

B = Total SJGS operation and maintenance labor paid and accrued excluding labor expenses chargeable to FERC accounts 920 through 935 inclusive.

Note: Any modifications to the methodology utilized for calculating the A&G Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordination Committee.

Exh. VI - 3

San Juan Operating Agreement

Exhibit VI-Attachment B

PAYROLL TAX RATIO FOR THE SAN JUAN GENERATING STATION (“SJGS”)

The Payroll Tax Ratio shall be applied to the following SJGS costs:


1)	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


2)	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.

The Payroll Tax Ratio shall be determined annually on the basis of the Operating Agent’s preceding years experience adjusted for known changes to comply with regulations applicable to Social Security and Unemployment Compensation as set forth herein unless otherwise agreed to by the participants. The Payroll Tax Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the ratio for the following year.

Payroll Tax Ratio = T/P

Where T = The Operating Agent’s total payroll tax expense chargeable to FERC Account 408.

P = The Operating Agent’s total base labor paid and accrued, less wages paid for time-off allowances plus accruals for time-off allowances.


Notes: (1)	Base labor is defined as an employee’s hourly rate times the number of hours worked plus an accrual for time-off allowances. In addition, base labor also includes overtime pay and special pay.


(2)	Time-off allowances are defined as vacation, illness and holiday time.

(3) Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay. Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan.

(4) Any modifications to the methodology utilized for calculating the Payroll Tax Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordinating Committee.

Exh. VI - 4

San Juan Operating Agreement

Exhibit VI-Attachment C

INJURIES AND DAMAGES RATIO FOR THE

SAN JUAN GENERATING STATION (“SJGS”)

The Injuries and Damages Ratio shall be applied to the following SJGS costs:


1)	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


2)	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.

The Injuries and Damages Ratio shall be determined annually on the basis of the Operating Agent’s preceding year’s experience as set forth herein unless otherwise agreed to by the participants. The Injuries and Damages Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the ratio for the following year.

Injuries and Damages Ratio = I/P

Where I =

The Operating Agent’s total injuries and damages expense chargeable to FERC Account 925, including payroll taxes, and pension and benefits on labor chargeable to FERC Account 925. The amount of payroll taxes and pension and benefits to be added are based on the ratios included in Exhibit VI, Attachments B and D, respectively. Note: Any injuries and damages expense charged direct to the SJGS are excluded from the determination of the Injuries and Damages Ratio.

P = The Operating Agent’s total base labor paid and accrued, less wages paid for time-off allowances plus accruals for time-off allowances less special pay and wages charged direct to FERC Account 925.


Notes: (1)	Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay. Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan.

(2) Any modifications to the methodology utilized for calculating the Injuries and Damages Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordination Committee.

Exh. VI - 5

San Juan Operating Agreement

Exhibit VI-Attachment D

PENSION AND BENEFITS RATIO FOR THE

SAN JUAN GENERATING STATION (“SJGS”)

The Pension and Benefits Ratio shall be applied to the following SJGS costs:


1)	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


2)	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.

The Pension and Benefits Ratio shall be determined annually on the basis of the Operating Agent’s preceding year’s experience as set forth herein unless otherwise agreed to by the participants. The Pension and Benefits Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the ratio for the following year.

Pension and Benefits Ratio = B/P

Where B = The Operating Agent’s total pension and benefits expense chargeable to FERC Account 926, including payroll taxes, and injuries and damages on labor chargeable to FERC Account 926. The amount of payroll taxes and injuries and damages to be added are based on the ratios included in Exhibit VI, Attachments B and C, respectively.

P = The Operating Agent’s total base labor paid and accrued, less wages paid for time-off allowances plus accruals for time-off allowances, less overtime, part-time, special pay not eligible for pension and benefits and wages charged direct to FERC Account 926.


Notes: (1)	Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay. Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan. Employee recognition awards are not eligible for pension and benefit loadings.

(2) Any modifications to the methodology utilized for calculating the Pension and Benefits Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordination Committee.

Exh. VI - 6

San Juan Operating Agreement

Exhibit VI−Attachment E

CAPITALIZED A&G RATIO APPLICABLE TO CAPITAL PROJECTS FOR THE SAN JUAN GENERATING STATION (“SJGS”)

The Operating Agent determines the appropriate A&G expense incurred for the benefit of the SJGS and to be billed to the SJGS as follows:

The FERC A&G accounts included in the A&G study are: 920, 921, 923, 930.2, 931 and 935.

Background

A questionnaire is sent to all managers that have A&G charges to the Bulk Power Business Unit to determine what percentage of their A&G expenses are capital-related and should be included in the development of the Capitalized A&G Ratios. Amounts are split between labor and other.


B.	Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) (see Exhibit VI Attachments B, C and D) are applied to the labor portion of the A&G determined above.

The Capitalized A&G Ratios, shall be applied to all SJGS construction costs except for long-term leased transportation and motorized equipment. The total amount of these construction dollars are utilized as the denominator in the calculation of the A&G Ratio described below.

Exh. VI - 7

Capitalized A&G Ratio = A/B

Where A = Administrative and general expense chargeable to FERC Accounts 920, 921, 923, 930.2, 931 and 935, including Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) as categorized separately in the A&G questionnaire for major and minor construction expenditures for the study period.

B = Total SJGS capital project amounts for the Bulk Power Business Unit as categorized between major and minor construction projects for the study period chargeable to FERC Accounts 107 and 108.

Exh. VI - 8

EXHIBIT VII

Example “Interim Invoice”

Exh. VII-1

Exh. VII-2

Exh. VII-3

Exh. VII-4

Exh. VII-5

Example “UG-CSA Invoice”

Exh. VII-6

Exh. VII-7

Exh. VII-8

Exh. VII-9

Exh. VII-10

Exh. VII-11

Exh. VII-12

Exh. VII-13

Exh. VII-14

Exh. VII-15

Exh. VII-16

Exh. VII-17

Exh. VII-18

Exh. VII-19

Exh. VII-20

Exh. VII-21

Exh. VII-22

Exh. VII-23

Exh. VII-24

Example “UPS Invoice”

Exh. VII-25

Exh. VII-26

EXHIBIT VIII

Proportional Adjustment of Voting Requirements

in Case of a Default and Suspension of the Rights of a Party or Participant

to Vote Pursuant to Section 35.4.1.

Example Calculation Based on Hypothetical Ownership Percentages:

In the following table, Participant D with Participation Shares in Units 3 and 4 is assumed to be the defaulting Participant. Participation Shares for Voting and Number of Participants for Voting are shown under original or pre-default conditions and are then adjusted as provided in Sections 18.4, 19.4, 20.5, and 21.4 after the right of Participant D to vote is suspended pursuant to Section 35.4.1.

Participation Shares for voting pursuant to Sections 18.4.1(a), 18.4.2(a), and 18.4.3(a) are adjusted as follows:

For Units:

The Adjusted Participation Share for a Participant = (That Participant’s Participation Share)/(The sum of the Participation Shares of all non-defaulting Participants in the affected Unit)

For Common Facilities:

Adjustments related to common facilities shall be proportional to any differing Participation Shares between Units. The above formula would be applied to each Unit and then summed and normalized over the applicable common facilities. Because San Juan Units are of unequal ratings, the normalization will be in proportion to each Unit’s rating rather than the even fractions in the example below where equally sized units were used for simplicity.

The numbers of Participants used for voting purposes pursuant to the requirements of Sections 18.4.1(b), 18.4.2(b), and 18.4.3(b) are adjusted by subtracting the number of defaulting Participants from the total number of Participants voting under those Sections.

Exh. VIII - 1



Unit or Facility	Original Participation Shares for Voting: §18.4.1(a), §18.4.2(a), and §18.4.3(a)		Original Number of Participants for Voting Purposes: §18.4.1(b), §18.4.2(b), and §18.4.3(b)	Adjusted Participation Shares for Voting - §18.4.1(a), §18.4.2(a), and §18.4.3(a)		Adjusted Number of Participants for Voting Purposes - §18.4.1(b), §18.4.2(b), and §18.4.3(b)
Unit 1			2			2
Participant A	50.00	%		50.00	%
Participant B	50.00	%		50.00	%
Unit 2			2			2
Participant A	50.00	%		50.00	%
Participant B	50.00	%		50.00	%
Unit 3			4			3
Participant A	20.00	%		28.57% ¹
Participant B	20.00	%		28.57	%
Participant C	30.00	%		42.86	%
Participant D	30.00	%		0.00	%
Unit 4			5			4
Participant A	10.00	%		12.50% ²
Participant B	10.00	%		12.50	%
Participant C	20.00	%		25.00	%
Participant D	20.00	%		0.00	%
Participant E	40.00	%		50.00	%
Unit 1 & 2 Common			2			2
Participant A	50.00	%		50.00	%
Participant B	50.00	%		50.00	%

_____________________________

¹ Computed on Unit 3 Participation Shares as follows: (Participant A) / (Participant A + Participant B + Participant C) = 20%/(20%+20%+30%) = 28.57%

² Computed on Unit 4 Participation Shares as follows: (Participant A) / (Participant A + Participant B + Participant C + Participant E) = 10%/(10%+10%+20%+40%) = 12.50%

Exh. VIII - 2



Unit 3 & 4 Common			5			4
Participant A	15.00	%		20.536% ³
Participant B	15.00	%		20.536%%
Participant C	25.00	%		33.928	%
Participant D	25.00	%		0.00	%
Participant E	20.00	%		25.000	%
Plant Common			5			4
Participant A	32.50	%		35.268% ⁴
Participant B	32.50	%		35.268	%
Participant C	12.50	%		16.964	%
Participant D	12.50	%		0.00	%
Participant E	10.00	%		12.500	%

_____________________________

³ Computed on Unit 3 and Unit 4 Common Participation Shares as follows: Unit 3 Contribution = (Participant A) / (Participant A + Participant B + Participant C) =

20%/(20%+20%+30%) = 28.571%; Unit 4 Contribution = (Participant A) / (Participant A + Participant B + Participant C + Participant E) = 10%/(10%+10%+20%+40%) = 12.500%.

Unit 3 & 4 Common = (Unit 3 Rating)/(Sum of Unit 3 and Unit 4 Ratings) * (Unit 3 Contribution) + (Unit 4 Rating)/(Sum of Unit 3 and Unit 4 Ratings) * (Unit 4 Contribution) = 1/2 (28.271%) + 1/2 (12.500%) = 20.536%

⁴ Computed on Plant Common Participation Shares as follows: Unit 1 Contribution = (Participant A) / (Participant A + Participant B) = 50%/(50%+50%) = 50.000%; Unit 2 Contribution = (Participant A) / (Participant A + Participant B) = 50%/(50%+50%) = 50.000%. Unit 3 Contribution = (Participant A) / (Participant A + Participant B + Participant C) = 20%/(20%+20%+30%) = 28.571%; Unit 4 Contribution = (Participant A) / (Participant A + Participant B + Participant C + Participant E) =

10%/(10%+10%+20%+40%) = 12.500%. Plant Common = (Unit 1 Rating)/(Plant

Rating) * (Unit 1 Contribution) + (Unit 2 Rating)/(Plant Rating) * (Unit 2 Contribution) + (Unit 3 Rating)/(Plant Rating) * (Unit 3 Contribution) + (Unit 4 Rating)/(Plant Rating) * (Unit 4 Contribution) = 1/4 (50.000%) + 1/4 (50.000%) + 1/4 (28.571%) + (1/4 (12.5000%) = 35.268%

Exh. VIII - 3

EXHIBIT IX

FIXED FUEL EXPENSE

SAN JUAN UNDERGROUND COAL SALES AGREEMENT (As Amended)

SECTION 7.3

Reclamation. (Any applicable post-expiration or post-termination reclamation costs described in said section.)

SECTION 8.2(A)

Base CIE Amount

SECTION 8.2(C)

Reimbursable Operating Costs enumerated in Exhibit “F” Paragraph I(1)

SECTION 8.2(D)

Administration Element

SECTION 8.2(E)

That part of CIE Reconciliation Amount associated with Base CIE or Non-SJCC Base CIE

SECTION 8.3(A)

Processing CIE Amount

SECTION 8.3(C)

Processing Administration Element

SECTION 8.3(D)

Processing CIE Reconciliation Amount

SECTION 8.5(A):

Other Reclamation (These are reclamation costs associated with former activities to supply surface-mined coal.)

SECTION 8.5(B)

Substitute REI

SECTION 8.5(C)

Payment of the Utility Payment Stream

SECTION 8.5(D)

Payments under the Ute ROW

SECTION 8.5(E)

Exh. IX - 1

Other Miscellaneous Costs

SECTION 8.5(F)

Dispute Costs

COAL SALES AGREEMENT BUY OUT AGREEMENT

SECTION 4.4:

Payment of SJCC Costs

TRANSPORTATION AGREEMENT BUYOUT AGREEMENT

SECTION 3.4:

Payment of SJTC Costs

Any costs allocated as Fixed Fuel Expense pursuant to Section 23.4.1.3 of this Agreement.

Applicable taxes and royalties on the above items shall be deemed Fixed Fuel Expense.

Capitalized Terms used in this Exhibit, not otherwise defined in this Agreement, are as defined in the above captioned agreements.

Exh. IX - 2

EXHIBIT X

VARIABLE FUEL EXPENSE

SAN JUAN UNDERGROUND COAL SALES AGREEMENT (As Amended)

SECTION 8.2(B)

Incremental CIE Amount

SECTION 8.2(C)

Reimbursable Operating Costs except those enumerated in Exhibit “F” Paragraph I(1) and only those reclamation costs directly associated with disturbance attributable to the underground mine.

SECTION 8.2(E)

That part of CIE Reconciliation Amount associated with Incremental CIE or Non-SJCC Incremental CIE

SECTION 8.3(B)

Reimbursable Processing Costs

SECTION 8.4

Non-SJCC Coal and Alternate Coal Costs

Capitalized Terms used in this Exhibit, not otherwise defined in this Agreement, are as defined in the above captioned agreements.

EXECUTION VERSION

EXIT DATE AMENDMENT AMENDING AND RESTATING THE

AMENDED AND RESTATED

SAN JUAN PROJECT PARTICIPATION AGREEMENT

AMONG

PUBLIC SERVICE COMPANY OF NEW MEXICO

TUCSON ELECTRIC POWER COMPANY

THE CITY OF FARMINGTON, NEW MEXICO

THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

July 31, 2015

EXECUTION VERSION

TABLE OF CONTENTS



SECTION	I. PARTIES AND INTRODUCTORY MATTERS	PAGE
1	PARTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	1
2	RECITALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	2
3	AGREEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	9
4	EFFECTIVE DATE AND TERMINATION . . . . . . . . . . . . . . . . . . . . . . . .	10
5	DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	12
	II. OWNERSHIP OF SAN JUAN PROJECT
6	OWNERSHIPS AND TITLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	24
7	CAPITAL IMPROVEMENTS AND RETIREMENTS OF SAN JUAN PROJECT AND PARTICIPANTS’ SOLELY OWNED FACILITIES . . .	29
8	WAIVER OF RIGHT TO PARTITION . . . . . . . . . . . . . . . . . . . . . . . . . . . .	34
9	BINDING COVENANTS. . . . . . . . . . . .	35
10	MORTGAGE AND TRANSFER OF PARTICIPANTS’ INTERESTS . . .	37
11	RIGHTS OF FIRST REFUSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	40
12	RIGHTS OF PNM AND TEP IN WATER AND COAL . . . . . . . . . . . . . .	46
13	SEVERANCE OF IMPROVEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . .	47
	III. ENTITLEMENTS TO OUTPUT OF SAN JUAN PROJECT
14	ENTITLEMENT TO CAPACITY AND ENERGY . . . . . . . . . . . . . . . . . .	48
15	CAPACITY ALLOCATION OF SWITCHYARD FACILITIES . . . . . . .	50
16	USE OF FACILITIES DURING CURTAILMENTS . . . . . . . . . . . . . . . . .	52
17	START-UP AND AUXILIARY POWER AND ENERGY REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	54

Exit Date Amendment 7/31/2015

EXECUTION VERSION



	IV. ADMINISTRATION
18	COORDINATION COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	55
19	ENGINEERING AND OPERATING COMMITTEE . . . . . . . . . . . . . . . .	60
20	FUELS COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	65
21	AUDITING COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	72
	V. BUDGETS AND OPERATING EXPENSES
22	OPERATION AND MAINTENANCE EXPENSES . . . . . . . . . . . . . . . . .	76
23	FUEL COSTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	85
24	ANNUAL BUDGETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	94
25	PAYMENT OF TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	95
26	MATERIALS AND SUPPLIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	96
27	EMERGENCY SPARE PARTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	98
	VI. OPERATING AGENT
28	OPERATION AND MAINTENANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . .	99
29	OPERATING EMERGENCY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	105
30	PAYMENT OF EXPENSES BY PARTICIPANTS . . . . . . . . . . . . . . . . . .	108
31	OPERATING INSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	111
32	SURPLUS OR RETIRED PROPERTY . . . . . . . . . . . . . . . . . . . . . . . . . . . .	115
33	REMOVAL OF OPERATING AGENT . . . . . . . . . . . . . . . . . . . . . . . . . . .	116
34	DEFAULTS BY OPERATING AGENT . . . . . . . . . . . . . . . . . . . . . . . . . . .	118

Exit Date Amendment 7/31/2015

EXECUTION VERSION



	VII. DEFAULTS, LIABILITY AND ARBITRATION
35	DEFAULTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	120
36	LIABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	127
37	ARBITRATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	132
	VIII. RETIREMENT AND RECONSTRUCTION
38	DESTRUCTION, DAMAGE OR CONDEMNATION OF A UNIT. . . . .	136
39	RIGHTS OF PARTICIPANTS UPON TERMINATION . . . . . . . . . . . . . .	138
40	DECOMMISSIONING OF THE PROJECT . . . . . . . . . . . . . . . . . . . . . . . .	139
40A	EXTENSION OF TERMINATION DATE FOR LARGE CAPITAL IMPROVEMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	140
40B	EXTENSION OF TERMINATION DATE AND COAL SUPPLY AGREEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	143
	IX. MISCELLANEOUS PROVISIONS
41	RELATIONSHIP OF PARTICIPANTS . . . . . . . . . . . . . . . . . . . . . . . . . . .	146
42	NOTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	147
43	OTHER PROVISIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	150
44	EXECUTION IN COUNTERPARTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	153
45	AMENDMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .	154

EXHIBIT I Real Property

EXHIBIT II [Omitted]

EXHIBIT III Switchyard Facilities

EXHIBIT IV Ownership of Equipment

EXHIBIT V O&M of Equipment

EXHIBIT VI A&G Expenses

EXHIBIT VII [Omitted]

EXHIBIT VIII Adjustment of Voting Requirements

iii

Exit Date Amendment 7/31/2015

EXECUTION VERSION

PART I

PARTIES AND INTRODUCTORY MATTERS

1.0 PARTIES:

The parties to this Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement (“Agreement”) are: PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“PNM”); TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“TEP”); THE CITY OF FARMINGTON, NEW MEXICO, an incorporated municipality and a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Farmington”); THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO, a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“LAC”); UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS, a political subdivision of the State of Utah (“UAMPS”); and PNMR DEVELOPMENT AND MANAGEMENT CORPORATION, a New Mexico corporation (“PNMR-D”). As of the effective date hereof, the parties are the participants in the San Juan Project, and are hereinafter sometimes referred to individually as a “Participant” and collectively as “Participants.”

Exit Date Amendment 7/31/2015

EXECUTION VERSION

2.0 RECITALS: This Agreement is made with reference to the following facts, among others:

2.1 PNM is an electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.

2.2 TEP is an electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of Arizona.

2.3 Farmington operates a municipal electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.

2.4 M-S-R Public Power Agency (“M-S-R”) is a public entity engaged in the generation, transmission, purchase and sale of electric power and energy in the western United States for the benefit of its member public agencies.

2.5 LAC operates a municipal electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.

2.6 Southern California Public Power Authority (“SCPPA”) is a public entity created to acquire, construct, finance, operate and maintain generation and transmission projects on behalf of its members.

2.7 City of Anaheim (“Anaheim”) operates a municipal utility in the State of California engaged in the generation, transmission and distribution of electric power.

2.8 UAMPS is a public entity created to plan, finance, develop, acquire, construct, improve, better, operate and maintain projects, or ownership interests or capacity

Exit Date Amendment 7/31/2015

EXECUTION VERSION

rights therein, for the generation, transmission and distribution of electric energy for the benefit of its members.

2.9 Tri-State Generation and Transmission Association, Inc. (“Tri-State”) is a cooperative corporation created pursuant to the laws of the State of Colorado. Tri-State’s primary functions involve the generation, transmission, transformation and sale of electricity to its member distribution cooperatives.

2.9(a) PNMR-D is a New Mexico corporation, a wholly owned subsidiary of PNM Resources, Inc. and an affiliate of PNM.

Exit Date Amendment 7/31/2015

EXECUTION VERSION

except for certain provisions which survived through provisions of the Transportation Agreement Buy Out Agreement.

2.11(a) PNM entered into a Coal Supply Agreement (“CSA”) for the supply of all the coal requirements for the San Juan Project from January 1, 2016 through June 30, 2022. PNM also entered into a Coal Combustion Residual Disposal Agreement (“CCRDA”), for the performance of all ash disposal activities for the San Juan Project over the term of the CSA and a Reclamation Services Agreement (“RSA”), for the performance of all reclamation obligations of the mines that have supplied coal for the San Juan Project from the RSA’s effective date until the full release of all reclamation and similar bonds associated with federal and state leases, agreements and permits. The anticipated effective date of the CSA, CCRDA and RSA is January 1, 2016.

2.11(b) In connection with the CSA, RSA and CCRDA becoming effective, PNM, TEP, SJCC and BHP Billiton New Mexico Coal, Inc., parent company to SJCC, terminated the UG-CSA and the CCBDA by entering into the UG-CSA Termination Agreement and the CCBDA Termination Agreement.

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Reservoir from 20,200 acre feet per year to 16,200 acre feet per year. Upon expiration of the above-referenced contract with the United States Department of the Interior, Bureau of Reclamation, on December 31, 2005, water from the Navajo Reservoir is delivered to the San Juan Project under contractual arrangements with the Jicarilla Apache Nation. From time-to-time, contracts for surplus water supply may also be entered into by the Operating Agent for supply to the San Juan Project. Additional water for use at the San Juan Project is based on a Grant of Authority for 8,000 acre-feet of water, dated August 18, 1980, from Utah International (predecessor in interest to SJCC) to PNM and TEP.

2.14 The San Juan Project Operating Agreement was executed as of December 21, 1973, effective as of July 1, 1969. The original Operating Agreement was modified by joint action of PNM and TEP, as follows: Modification No. 1 on May 16, 1979, Modification No. 2 on December 31, 1983, Modification No. 3, on July 17, 1984, Modification No. 4 on October 25, 1984, Modification No. 5 on July 1, 1985, Modification No. 6 on April 1, 1993, Modification No. 7 on April 1, 1993, Modification No. 8 on

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September 15, 1993, Modification No. 9 on January 12, 1994 and Modification No. 10 on November 30, 1995 (the original of such Operating Agreement, as amended by Modifications 1 through 10, is referred to herein as the “Operating Agreement”).

2.16 On May 16, 1979, TEP and PNM entered into an agreement whereby on that date TEP conveyed to PNM TEP’s 50 percent undivided ownership interest in Unit 4.

2.17 On November 17, 1981, PNM transferred an 8.475 percent undivided ownership interest in Unit 4 to Farmington.

2.18 On December 31, 1983, PNM transferred a 28.8 percent undivided ownership interest in Unit 4 to M-S-R.

2.19 On October 31, 1984, TEP transferred its 50 percent undivided ownership interest in Unit 3 to Alamito Company, which later changed its name to Century Power Company (“Century”).

2.20 On July 1, 1985, PNM transferred a 7.2 percent undivided ownership interest in Unit 4 to LAC.

2.21 On July 1, 1993, Century transferred a 41.8 percent undivided ownership interest in Unit 3 to SCPPA.

2.22 On August 12, 1993, PNM transferred a 10.04 percent undivided ownership interest in Unit 4 to Anaheim.

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2.23 On June 2, 1994, PNM transferred a 7.028 percent undivided ownership interest in Unit 4 to UAMPS.

2.24 On January 2, 1996, Century transferred an 8.2 percent undivided ownership interest in Unit 3 to Tri-State.

2.25 Farmington, M-S-R, LAC, SCPPA, Anaheim, UAMPS and Tri-State were classified as “Unit Participants” in the San Juan Project, pursuant to the Co-Tenancy Agreement.

2.27 As of October 27, 1999, the participants entered into the San Juan Project Participation Agreement (“Original San Juan PPA”). The purpose of the Original San Juan PPA was to amend and restate, and to replace in their entirety, the Co-Tenancy Agreement and the Operating Agreement and to set out in one instrument all of the matters previously included in the Co-Tenancy Agreement and the Operating Agreement.

2.28 As of March 23, 2006, the participants entered into an Amended and Restated San Juan Project Participation Agreement to amend and restate the Original San Juan PPA to reflect certain amendments agreed to by the participants including, but not limited to, changes to the provisions of the Original San Juan PPA pertaining to fuel supply. Certain changes to the Amended and Restated San Juan Project Participation Agreement were subsequently accepted by FERC for filing as PNM Rate Schedule No. 144.

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2.29 The Participants and the Exiting Participants entered into the San Juan Project Restructuring Agreement (“Restructuring Agreement”) relating to the restructuring of ownership interests in the San Juan Project and the retirement of Units 2 and 3. The Participants and the Exiting Participants have also entered into the San Juan Decommissioning and Trust Funds Agreement (“Decommissioning Agreement”), which relates to decommissioning of the San Juan Project, and the Amended and Restated Mine Reclamation and Trust Funds Agreement (“Mine Reclamation Agreement”), which relates to reclamation of the San Juan Mine.

2.30 Under the terms of the Restructuring Agreement, the Exiting Participants will terminate their active involvement in the San Juan Project as of the Exit Date, and as of the Exit Date PNM and PNMR-D will acquire the San Juan Project interests of the Exiting Participants.

2.31 As of the Exit Date the Exiting Participants will no longer be Participants in the San Juan Project or parties to this Agreement.

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3.0 AGREEMENT: The Participants, for and in consideration of the mutual covenants to be by them kept and performed, agree as follows.

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4.0 EFFECTIVE DATE AND TERMINATION:

4.2 Following execution, PNM shall file a copy of this Agreement with the FERC in a timely manner. In such filing, PNM shall request waiver of applicable FERC notice requirements in order to allow this Agreement to become effective as of the Exit Date, as provided for in the Restructuring Agreement. All other Participants shall support PNM’s filing by the prompt filing of a certificate or letter of concurrence or intervention in support of the filing or shall not take any action to oppose the filing of this Agreement.

4.3 Following an order by the FERC or any other regulatory agency having jurisdiction, if any, the Participants shall each review such order, letter or communication to determine if the FERC or any agency having jurisdiction has changed or modified a condition or conditions, deleted a condition or conditions, or imposed a new condition or conditions with regard to this Agreement; or has conditioned its approval of this Agreement upon changes or modifications to a condition or conditions, deletion of a condition or conditions or imposition of a new condition or conditions. The Participant receiving such order, letter or communication shall promptly provide a copy of such order, letter or communication to the other Participants. Within fifteen (15) business days after receipt by the other Participants of the copy of the order, letter or communication, the Participants

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shall indicate to each other in writing their acceptance or rejection of this Agreement based upon any changes, modifications, deletions or new conditions required by the FERC or any agency having jurisdiction. A failure to notify within said fifteen (15) day period shall be the equivalent to a notification of acceptance. If any Participant rejects this Agreement because the FERC or any agency having jurisdiction has modified a condition, deleted a condition or imposed a new condition in this Agreement, or has conditioned its approval on such a change, modification, deletion or new condition, the Participants will be deemed to have rejected this Agreement and they shall attempt, in good faith, to renegotiate the terms and conditions of this Agreement to resolve such changed, modified, deleted or new condition to the satisfaction of the Participants within one hundred twenty (120) days after the date of such order, letter or communication and thereafter to obtain requisite regulatory approval of such renegotiated agreement.

4.4 This Agreement shall continue in force and effect until July 1, 2022, unless otherwise agreed in writing by the Participants or as provided for in Sections 40A or 40B.

4.5 The Exiting Participants agree to the amendment of the Amended and Restated San Juan Project Participation Agreement as provided in this Agreement to effectuate their removal as participants in the San Juan Project as of the Exit Date. The Participants agree to such removal and further agree that as of the Exit Date, the Exiting Participants’ obligations with respect to the San Juan Project are governed solely by the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement.

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5.0 DEFINITIONS: The following terms, when used herein with initial capitalization, and whether in the singular or the plural, shall have the meaning specified:

5.1 ACCOUNTING PRACTICE: Generally accepted accounting principles in accordance with FERC Accounts applicable to electric utility operations.

5.2 AGREEMENT: This Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement, including all exhibits and attachments hereto, and as may be modified or amended from time to time.

5.3 AUDITING COMMITTEE: A committee which is described in Section 21.

5.4 AVAILABLE OPERATING CAPACITY: The maximum net electrical capacity of each installed and operating Unit which is available at any given time to the Participants at the 345 kV buses.

5.4(a) AVAILABLE PRE-EXISTING STOCKPILE TONS has the meaning provided for in Section 12.1(C)(1) of the CSA.

5.5 CAPACITY: Electrical rating expressed in megawatts (“MW”).

5.6(a) CBI means capital budget item.

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5.6(b) CCBDA means the Coal Combustion Byproducts Disposal Agreement between PNM, TEP and SJCC, which was terminated by the CCBDA Termination Agreement.

5.6(c) CCBDA TERMINATION AGREEMENT means the Coal Combustion Byproducts Disposal Agreement Termination and Mutual Release Agreement between SJCC, BHP Billiton, PNM and TEP.

5.6(d) CCR means ash and gypsum byproducts produced by the San Juan Project.

5.6(e) CCRDA means the Coal Combustion Residuals Disposal Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016.

5.8 COAL SALES AGREEMENT BUY OUT AGREEMENT: Agreement between PNM, TEP and SJCC executed on August 31, 2001, as may be amended or modified from time to time.

5.9 COMMON PARTICIPATION SHARE: Each Participant’s percentage ownership interest as set forth in Section 6.2.6.

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5.11 COORDINATION COMMITTEE: A committee which is described in Section 18.

5.12 CO-TENANCY AGREEMENT: The agreement described in Section 2.13.

5.12(a) CSA means the Coal Supply Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016, as may be amended or replaced.

5.12(b) DECOMMISSIONING AGREEMENT means the San Juan Project Decommissioning and Trust Funds Agreement among the Participants and the Exiting Participants executed concurrently with the Restructuring Agreement and effective on the Exit Date.

5.13 DR AGREEMENT: The agreement described in Section 2.26, as amended from time to time.

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5.16 ENERGY: The accumulated amount of power produced over a stated time interval, expressed in kilowatt hours (“kWh”) or megawatt hours (“MWh”).

5.17 ENGINEERING AND OPERATING COMMITTEE: A committee which is described in Section 19.

5.17(b) EXITING PARTICIPANTS means those entities that will transfer all of their respective rights, titles and interests in and to their Ownership Interests to PNM or PNMR-D and terminate their active involvement in the operation of SJGS on the Exit Date, except as expressly provided for in the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement; the Exiting Participants are M-S-R, Anaheim, SCPPA and Tri-State.

5.18 FC LINE: That 345 kV transmission line between the San Juan generating station and the Four Corners generating plant.

5.19 [Omitted]

5.20 FERC: The Federal Energy Regulatory Commission or any successor thereto.

5.21 FERC ACCOUNTS: The FERC Uniform System of Accounts prescribed for Public Utilities and Licensees (Class A and Class B). References in this Agreement to a

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specific FERC account number shall mean the number in effect as of the date of this Agreement and any successor account number.

5.21(a) FORCE MAJEURE TONS has the meaning provided for in Section 12.1(C)(3) of the CSA.

5.22 FUELS COMMITTEE: A committee which is described in Section 20.

5.22(a) LARGE CAPITAL IMPROVEMENT has the meaning provided for in Section 18.4.4.

5.22(a) LEGACY COSTS means those costs payable under Sections 8.2, 8.3 and 8.4 of the CSA.

5.23 MATERIALS AND SUPPLIES: Those materials and supplies, the cost of which is charged to FERC Account 154, which are stocked for use in the operation and maintenance of the San Juan Project.

5.23(a) MINE RECLAMATION AGREEMENT means the Amended and Restated Mine Reclamation and Trust Funds Agreement among the Participants and the Exiting Participants executed concurrently with the Restructuring Agreement.

5.24 [Omitted]

5.25 MINIMUM NET GENERATION: The lowest net load at which each Unit can be reliably maintained in service on a continuous basis on coal fuel.

5.26 [Omitted]

5.27 NET EFFECTIVE GENERATING CAPACITY: The maximum continuous ability of each Unit to produce power, less auxiliary power requirements.

5.28 NET ENERGY GENERATION: The Energy generated by each Unit which is available to the respective Participants at the 345 kV bus.

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5.29 OPERATING ACCOUNT: The bank account(s) in the names of the Participants established by the Operating Agent pursuant to Section 28.

5.31 OPERATING AGREEMENT: The agreement described in Section 2.14.

5.32 OPERATING EMERGENCY: An unplanned event or circumstance at the San Juan Project which reduces or may reduce the availability of Capacity or Energy from a Unit.

5.33 OPERATING FUNDS: Monies advanced to, and disbursed by, the Operating Agent on behalf of the Participants in accordance with this Agreement.

5.34 OPERATING INSURANCE: Policies of insurance secured or to be secured and maintained in accordance with Section 31.

5.36 ORIGINAL SAN JUAN PPA: The San Juan Project Participation Agreement dated October 27, 1999.

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5.36(a) OWNERSHIP INTEREST means a Participant’s percentage undivided ownership interest in a Unit and in common equipment and facilities and as increased, decreased, acquired or transferred as provided in Sections 6.3 and 6.4 of the Restructuring Agreement, and rights incidental thereto.

5.37 PARTICIPANT: PNM, TEP, Farmington, LAC, UAMPS, or PNMR-D.

5.39 PARTICIPATION SHARE: Each Participant’s percentage ownership interest in the various elements of the San Juan Project as set forth in Section 6.

5.39(a) PRE-EXISTING STOCKPILE COAL means coal that as of the effective date of the Restructuring Agreement is stockpiled on SJCC property.

5.41 PROJECT COAL INVENTORY: The sum of coal in coal storage piles, silos, conveying systems, hoppers, and all other coal storage at the San Juan Project as accounted in FERC Account No. 151.

5.42 PRUDENT UTILITY PRACTICE: Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the

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relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in the light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Prudent Utility Practice is intended to be acceptable practices, methods or acts generally accepted in the industry, as such practices may be affected by special operational design characteristics of the San Juan Project, the quality and quantity of fuel delivered in accordance with the CSA or successor agreement, the rights and obligations of the Participants in accordance with this Agreement and any other special circumstances affecting the Operating Work.

5.42(a) REMAINING PARTICIPANTS means those Participants that will continue participation, or acquire an Ownership Interest, in the San Juan Project on and after the Exit Date; the Remaining Participants are PNM, TEP, Farmington, UAMPS, LAC and PNMR-D.

5.42(b) RESTRUCTURING AGREEMENT means the San Juan Project Restructuring Agreement among the Participants and the Exiting Participants.

5.42(c) RSA means the Reclamation Services Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016.

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plant. The San Juan Project does not include distribution lines, transmission lines, equipment in the Switchyard Facilities or other facilities owned exclusively by a Participant.

5.43(a) SJGS means the San Juan Generating Station.

5.43(b) SJCC means San Juan Coal Company, a Delaware corporation, or its successors or assigns.

5.44 SWITCHYARD FACILITIES: The switchyard facilities required for the San Juan Project as shown by materials listed in Exhibit III, attached hereto and incorporated herein.

5.44(a) TIER 1 TONNAGE ALLOCATION means a schedule allocating Tier 1 Tons on a monthly basis based on the SJGS monthly planned coal consumption.

5.44(b) TIER 1 TONS means, with respect to: (i) each of 2016 and 2017, 5.750 million tons; (ii) each of 2018 and 2019, 2.8 million tons; (iii) each of 2020 and 2021, 2.65 million tons; and (iv) in 2022, 1.4 million tons.

5.44(c) TIER 2 TONS means all tons delivered to and accepted by SJGS in a year in excess of Tier 1 Tons.

5.45 [Omitted]

5.46 TRANSPORTATION AGREEMENT BUY OUT AGREEMENT: Agreement between PNM, TEP and San Juan Transportation Company (“SJTC”) executed on August 31, 2001, as may be amended or modified from time to time, which terminated the Transportation Agreement with SJTC dated April 30, 1984.

5.46(a) UG-CSA TERMINATION AGREEMENT means the Underground Coal Sales Agreement Termination and Mutual Release Agreement among PNM, TEP, SJCC and BHP Billiton New Mexico Coal.

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5.47 UNDERGROUND COAL SALES AGREEMENT: Agreement between PNM, TEP and SJCC executed on August 31, 2001, as amended or modified, which was terminated by the UG-CSA Termination Agreement.

5.48 UNIT: Unit 1, Unit 2, Unit 3 or Unit 4.

5.49 UNIT 1: The second operating unit of the San Juan Project, which was placed in commercial service on December 31, 1976 and which presently has a net capacity rating of 340 MW.

5.50 UNIT 2: The first operating unit of the San Juan Project, which was placed in commercial service on November 30, 1973 and which has been retired from service.

5.51 UNIT 3: The third operating unit of the San Juan Project, which was placed in commercial service on December 31, 1979 and which has been retired from service.

5.52 UNIT 4: The fourth operating unit of the San Juan Project, which was placed in commercial service on April 27, 1982 and which presently has a net capacity rating of 507 MW.

5.54 [Omitted]

5.55 [Omitted]

5.56 WATER CONTRACT(S): The applicable contract or contracts under which water is delivered to the San Juan Project, as more fully described in Section 2.12.

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5.57 WILLFUL ACTION:

5.57.1 Action taken or not taken by a Participant (or the Operating Agent), at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under a Project Agreement, which action is knowingly or intentionally taken or not taken with conscious indifference to the consequences thereof or with intent that injury or damage would probably result therefrom; or

5.57.2 Action taken or not taken by a Participant (or the Operating Agent) at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under a Project Agreement, which action has been determined by final arbitration award or final judgment or judicial decree to be a material default under a Project Agreement and which action occurs or continues beyond the time specified in such arbitration award or judgment or judicial decree for curing such default, or if no time to cure is specified therein, occurs or continues beyond a reasonable time to cure such default; or

5.57.3 Action taken or not taken by a Participant (or the Operating Agent), at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under a Project Agreement, which action is knowingly or intentionally taken or not taken with the knowledge that such action taken or not taken is a material default under a Project Agreement.

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5.57.4 The phrase “employees having management or administrative responsibility,” as used in this Section 5.57, means employees of a Participant who are responsible for one or more of the executive functions of planning, organizing, coordinating, directing, controlling and supervising such Participant’s performance under a Project Agreement; provided however, that, with respect to employees of the Operating Agent acting in its capacity as such and not in its capacity as a Participant, such phrase shall refer only to (i) the senior employee of the Operating Agent on duty at the San Juan Project who is responsible for the operation of the Units, and (ii) anyone in the organizational structure of the Operating Agent between such senior employee and an officer.

5.57.5 Willful Action does not include any act or failure to act which is merely involuntary, accidental or negligent.

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PART II

OWNERSHIP OF SAN JUAN PROJECT

6.0 OWNERSHIPS AND TITLES:

6.1 PNM and TEP, respectively, each has an undivided one-half (1/2) ownership interest in the real property interests described in Exhibit I as Parcels A through F.

6.2 Unless otherwise provided in Exhibit IV, the Units and other facilities of the San Juan Project and Capital Improvements shall be owned and title held by the Participants in the following percentages:

6.2.1 For Units 1 and 2 and for all equipment and facilities directly related to Units 1 and 2 only, in accordance with the following percentages:

6.2.1.1 PNM: 50 percent

6.2.1.2 TEP: 50 percent

6.2.1.3 [Omitted]

6.2.1.4 Farmington: 0 percent

6.2.1.5 [Omitted]

6.2.1.6 LAC: 0 percent

6.2.1.7 [Omitted]

6.2.1.8 [Omitted]

6.2.1.9 UAMPS: 0 percent

6.2.1.10 PNMR-D: 0 percent

6.2.2 For Unit 3 and for all equipment and facilities directly related to Unit 3 only, in accordance with the following percentages:

6.2.2.1 PNM: 100 percent

6.2.2.2 TEP: 0 percent

6.2.2.3 [Omitted]

6.2.2.4 Farmington: 0 percent

6.2.2.5 [Omitted]

6.2.2.6 LAC: 0 percent

6.2.2.7 [Omitted]

6.2.2.8 [Omitted]

6.2.2.9 UAMPS: 0 percent

6.2.2.10 PNMR-D: 0 percent

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6.2.3 For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:

6.2.3.1 PNM: 64.482 percent

6.2.3.2 TEP: 0 percent

6.2.3.3 [Omitted]

6.2.3.4 Farmington: 8.475 percent

6.2.3.5 [Omitted]

6.2.3.6 LAC: 7.20 percent

6.2.3.7 [Omitted]

6.2.3.8 [Omitted]

6.2.3.9 UAMPS: 7.028 percent

6.2.3.10 PNMR-D: 12.815 percent

6.2.4 For equipment and facilities common to Units 1 and 2 only, in accordance with the following percentages:

6.2.4.1 PNM: 50 percent

6.2.4.2 TEP: 50 percent

6.2.4.3 [Omitted]

6.2.4.4 Farmington: 0 percent

6.2.4.5 [Omitted]

6.2.4.6 LAC: 0 percent

6.2.4.7 [Omitted]

6.2.4.8 [Omitted]

6.2.4.9 UAMPS: 0 percent

6.2.4.10 PNMR-D: 0 percent

6.2.5 For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:

6.2.5.1 PNM: 64.482 percent

6.2.5.2 TEP: 0 percent

6.2.5.3 [Omitted]

6.2.5.4 Farmington: 8.475 percent

6.2.5.5 [Omitted]

6.2.5.6 LAC: 7.200 percent

6.2.5.7 [Omitted]

6.2.5.8 [Omitted]

6.2.5.9 UAMPS: 7.028 percent

6.2.5.10 PNMR-D: 12.815 percent

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6.2.6 For equipment and facilities common to all of the Units in accordance with the following percentages:

6.2.6.1 PNM: 58.671 percent

6.2.6.2 TEP: 20.068 percent

6.2.6.3 [Omitted]

6.2.6.4 Farmington: 5.076 percent

6.2.6.5 [Omitted]

6.2.6.6 LAC: 4.309 percent

6.2.6.7 [Omitted]

6.2.6.8 [Omitted]

6.2.6.9 UAMPS: 4.203 percent

6.2.6.10 PNMR-D: 7.673 percent

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capacity in excess of the combined installed capacity of Units 1, 2, 3 and 4 for the San Juan Project.

6.2.8 Exhibit IV (a through h), attached hereto and incorporated herein, is a partial list of equipment and facilities of the San Juan Project and reflects the Participants’ ownership interests therein. This exhibit is to provide the Engineering and Operating Committee, the Auditing Committee, the Fuels Committee and the Coordination Committee with guidelines for carrying out their duties under this Agreement.

6.2.10 Materials and Supplies shall be owned by the Participants in proportion to their respective current investments in the Materials and Supplies.

6.3 Upon the effective date of this Agreement, the Emergency Coal Storage Pile shall be owned as follows:

6.3.1 PNM: 73.297 percent

6.3.2 TEP: 19.8 percent

6.3.3 [Omitted]

6.3.4 Farmington: 2.559 percent

6.3.5 [Omitted]

6.3.6 LAC: 2.175 percent

6.3.7 [Omitted]

6.3.8 [Omitted]

6.3.9 UAMPS: 2.169 percent

6.3.10 PNMR-D: 0 percent

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6.4 In the event that a Participant transfers or assigns any of its rights, titles or interests in and to the San Juan Project in accordance with the terms and conditions of this Agreement, the Participants (including the transferee or assignee of a Participant) shall jointly make, execute and deliver a supplement to this Agreement in recordable form which shall describe with particularity and in detail the rights, titles and interests of each Participant following such transfer or assignment.

6.5 PNM and TEP own as tenants in common the Switchyard Facilities described in Exhibit III in equal, undivided one-half (1/2) interests.

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7.0 CAPITAL IMPROVEMENTS AND RETIREMENTS OF SAN JUAN PROJECT AND PARTICIPANTS’ SOLELY OWNED FACILITIES:

7.1 The Participants recognize that from time to time it may be necessary or desirable to make Capital Improvements to and retirements of facilities comprising the San Juan Project.

7.2 Any such Capital Improvements and retirements shall be noted by an appropriate revision in or supplement to the appropriate exhibits hereto attached.

7.3 The rights, titles and interests, including Participation Shares, of a Participant in and to any Capital Improvements shall be as provided for the respective classes of property described in Section 6. The Participants shall be obligated for the costs of such Capital Improvements in the same percentages as their Participation Shares.

7.5 The Operating Agent shall submit to the Participants a forecast of cash requirements by months for Capital Improvements. Said forecast will be submitted on a yearly basis after final budget approvals have been made. A revised forecast shall be submitted when the capital expenditures budget is revised, or when significant changes in monthly expenditures from those previously forecast are anticipated. The Operating Agent

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shall be authorized to make additional expenditures related to Capital Improvements; provided, however, that such additional expenditures for Capital Improvements shall not exceed the sum of one hundred thousand dollars ($100,000) or cause the total expenditure limit contained in the capital expenditures budget to be exceeded, unless also authorized by the Engineering and Operating Committee, or by the Coordination Committee if the total expenditure for such Capital Improvement exceeds five hundred thousand dollars ($500,000).

7.6 In the event of the removal or retirement of any facilities comprising part of the San Juan Project, any proceeds realized from the salvage of such facilities shall, unless otherwise provided in the Decommissioning Agreement, be distributed to the Participants in accordance with their Participation Shares therein, or shall be applied on account of the Participant’s obligations to pay for Capital Improvements replacing facilities removed or retired. Units of Property retired from service shall be disposed of on the best available terms as soon as practicable.

7.7 Each Participant shall have the right, at its own expense, to add facilities to the Switchyard Facilities, provided the Engineering and Operating Committee approves the design of such additional facilities and determines that space is available therefor, and that such committee also determines that such additional facilities will not (i) infringe upon the rights of another Participant in the Switchyard Facilities, (ii) unreasonably interfere with future expansion plans at the San Juan Project, (iii) impair or interfere with the contractual rights of another Participant, or (iv) jeopardize the reliability of another Participant’s system. The Engineering and Operating Committee shall have authority to impose conditions on a Participant allowed to make such additions in order to protect the other

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Participants consistent with applicable rules and regulations of the FERC. Such facilities shall be and remain the sole and exclusive property of the Participant installing same until and unless the Coordination Committee determines that such facilities are necessary and beneficial for operation of the San Juan Project as a whole. In the event of such determination, the facilities shall be acquired as a part of the San Juan Project by the Participants and compensation shall be paid to the selling Participant by the Participants acquiring such interest based on the net book value of such facilities.

7.8 Each Participant shall have the right, at its own expense, to add protective relay or communication equipment to facilities solely owned by it, if the Participant determines the protective relay or communication equipment is needed for the protection of its electric system, provided the Engineering and Operating Committee approves the design of such additional equipment and determines that space is available therefor, and that such committee also determines that such additional facilities will not (i) infringe upon the rights of another Participant in the facilities, (ii) unreasonably interfere with future expansion plans at the San Juan Project, (iii) impair or interfere with the contractual rights of another Participant, or (iv) jeopardize the reliability of another Participant’s system.

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administrative and general expense shall be included in or added to such lease payments for transportation and motorized equipment which, in lieu of acquiring such equipment by purchase, has been leased on a long-term basis.

7.11 Administrative and general expenses which have been incurred by the Operating Agent which are applicable to authorized Capital Improvements, shall be applied monthly to construction costs incurred during the preceding month. A rate will be developed by the Operating Agent every three (3) years in conjunction with the administrative and general (“A&G”) expenses study referenced in Attachment A to Exhibit VI. The current methodology for calculating the A&G Ratio for Capital Improvements is set forth in Exhibit VI, Attachment E. If any Participant believes that the method used in determining the A&G Ratio for Capital Improvements results in an unreasonable burden on such Participant(s), such Participant(s) may request that said method used in determining said ratio be submitted to the Auditing Committee for review in accordance with the procedures set out in Sections 22.6.1 through 22.6.4.

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7.12 Excluded from the charges in Section 7.11 are expenses incurred under Section 36.2.

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8.0	WAIVER OF RIGHT TO PARTITION:

8.1 The Participants accept title to their respective interests in the San Juan Project, water rights, lands, land rights and improvements thereon as tenants in common, and agree that their interests therein shall be held in such tenancy in common for the duration of the term of this Agreement, including any extensions thereof. While this Agreement, including any extensions thereof, remains in force and effect, each Participant agrees as follows:

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9.0 BINDING COVENANTS:

9.1 Except as otherwise provided in Section 9.3, all of the respective covenants and obligations of each of the Participants set forth and contained in the Project Agreements shall bind and shall be and become the respective obligations of:

9.1.1 Each Participant;

9.1.3 All receivers, assignees for the benefit of creditors, bankruptcy trustees and referees of a Participant;

9.1.4 All other persons, firms, partnerships or corporations claiming through or under any of the foregoing; and

9.1.5 Any successors or assigns of any of those mentioned in Sections 9.1.1 to 9.1.4, inclusive,

and shall be obligations running with the Participants’ rights, titles and interests in the San Juan Project, with all of the rights, titles and interests (if any) of each Participant in, to and under this Agreement and with their rights, titles and interests in the water rights, lands, land rights and the improvements thereon. It is the specific intention of this provision that all of such covenants and obligations shall be binding upon any party which acquires any of the rights, titles and interests of any of the Participants in the San Juan Project, in, to and under this Agreement, and/or in the water rights, lands, land rights or the improvements thereon, and that all of the above-described persons and groups shall be obligated to use such Participant’s rights, titles and interests in the San Juan Project, in, to and under this

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Agreement, and in the water rights, lands, land rights and the improvements thereon, for the purpose of discharging its covenants and obligations under this Agreement.

9.2 The rights, titles and interests of each Participant in the San Juan Project, its rights, titles and interests in, to and under this Agreement and its rights, titles and interests in and to the water rights, lands, land rights and improvements thereon, shall inure to the benefit of its successors and assigns.

9.3 Any mortgagee, trustee or secured party, or any receiver or trustee appointed pursuant to the provisions of any present or future mortgage, deed of trust, indenture or security agreement creating a lien upon or encumbering the rights, titles or interests of any Participant in the San Juan Project, in, to and under this Agreement and/or in the water rights, lands, land rights or the improvements thereon, and any successor thereof by action of law or otherwise, and any purchaser, transferee or assignee of any thereof, shall not be obligated to pay any monies accruing on account of any of the obligations or duties of such Participant under this Agreement incurred prior to the taking of possession or the initiation of foreclosure or other remedial proceedings by such mortgagee, trustee or secured party.

9.4 In the event that any or all of the provisions of this Section 9 shall not be legally effective as to any Participant, or its mortgagees, trustees, secured parties, receivers, successors or assigns, then such Participant shall not be deemed in violation of this Section 9 by reason thereof.

9.5 Nothing in this Section 9 or in this Agreement shall be deemed to change any rights, titles or interests to water rights, lands, land rights and the improvements thereon.

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10.0 MORTGAGE AND TRANSFER OF PARTICIPANTS’ INTERESTS:

10.1 The Participants shall have the right at any time and from time to time to mortgage, create or provide for a security interest in or convey in trust their respective rights, titles and interests in the San Juan Project, their respective rights, titles and interests in, to and under a Project Agreement and/or their rights, titles and interests in the water rights, lands, land rights or the improvements to be built thereon to a trustee or trustees under deeds of trust, mortgages or indentures, or to secured parties under a security agreement, as security for their present or future bonds or other obligations or securities, and to any successors or assigns thereof without need for the prior consent of the other Participants, and without such mortgagee, trustee or secured party assuming or becoming in any respect obligated to perform any of the obligations of the Participants.

10.2 Any mortgagee, trustee or secured party under present or future deeds of trust, mortgages, indentures or security agreements of any of the Participants and any successor or assign thereof, and any receiver, referee, or trustee in bankruptcy or reorganization of any of the Participants, and any successor by action of law or otherwise, and any purchaser, transferee or assignee of any thereof may, without need for the prior consent of the other Participants, succeed to and acquire all the rights, titles and interests of such Participant in the San Juan Project, in, to and under the Project Agreements and/or the rights, titles and interests of such Participant in the water rights, lands, land rights and improvements thereon, and may take over possession of or foreclose upon said property, rights, titles and interests of such Party.

10.3 Except as otherwise provided in Sections 10.1, 10.2 or 10.4 or, with respect to a transfer or assignment by a Participant to another Participant as provided in Section 11,

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no Participant shall transfer or assign its respective rights, titles and interests in the San Juan Project, in, to and under this Agreement and/or in the water rights, land, land rights and the improvements thereon, without the prior written consent of the other Participants, which consent shall not be unreasonably withheld.

10.4 Each Participant shall have the right to transfer or assign its respective rights, titles and interests in the San Juan Project, in, to and under this Agreement and/or in the water rights, land, land rights and the improvements thereon, without the need for prior consent of the other Participants, at any time to any of the following:

10.4.1 To any corporation or other entity acquiring all or substantially all of the property of such Participant; or

10.4.2 To any corporation or entity into which or with which such Participant may be merged or consolidated; or

10.4.3 To any corporation or entity the stock or ownership of which is wholly owned by a Participant; or

10.4.4 To any corporation or other entity which owns all of the outstanding common stock or other ownership interest of a Participant (its “Parent”); or

10.4.5 To any corporation or other entity the common stock or other ownership interest of which is wholly owned by the Parent of a Participant.

10.5 Except as otherwise provided in Sections 10.1, 10.2 and 9.3, any successor to the rights, titles and interests of a Participant in the San Juan Project, to the rights, titles and interests of a Participant in, to and under the Project Agreements and/or in the water rights, lands, land rights or improvements thereon shall assume and agree to fully perform and discharge all of the obligations hereunder of such Participant, and such successor shall

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notify the other Participants in writing of such transfer, assignment or merger, and shall furnish to the other Participants evidence of such transfer, assignment or merger. Any such successor shall specifically agree in writing with the remaining Participants at the time of such transfer, assignment or merger that it will not transfer or assign any rights, titles and interests acquired from the assigning Participant without complying with the terms and conditions of Section 11.

10.6 No Participant shall be relieved of any of its obligations and duties to the other Participants by a transfer, assignment or merger under this Section 10 without the express prior written consent of the remaining Participants, which consent shall not be unreasonably withheld.

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11.0 RIGHTS OF FIRST REFUSAL:

11.1 The purpose of this Section 11 is to set forth the manner in which all existing or future rights of first refusal, pertaining to the transfer of interests in the San Juan Project, shall be exercised. Except as provided in Section 10, PNM has a right of first refusal with respect to the proposed transfer of any ownership interest in the San Juan Project by any Participant and TEP has a right of first refusal with respect to PNM’s proposed transfer of an interest in Unit 1 or Unit 2 and associated common property. The existence of other rights of first refusal shall be as provided in other appropriate instruments. Nothing in this Section 11 shall be construed to limit or expand the rights of first refusal of any Participant.

11.2 Except as provided in Section 10, should a Participant desire to assign, transfer, convey or otherwise dispose of (hereinafter collectively referred to as “Assign”) its rights, titles and interests in the San Juan Project, or its rights, titles and interests in, to and under the Project Agreements, or its rights, titles and interests in the water rights, lands, land rights or the improvements thereon or any part thereof or interest therein (hereinafter referred to as “Transfer Interest”), to any person, company, corporation or governmental agency (hereinafter referred to as “Outside Party”), the Participant desiring to Assign shall first make an offer to sell the Transfer Interest to a Participant(s) having a right of first refusal, on the basis of the applicable amount as set out in either Section 11.2.1 or Section 11.2.2:

11.2.1 Where the Outside Party proposes to purchase for a specified monetary amount, from the Participant desiring to Assign, an interest only in the San Juan Project and/or in contract rights, water rights, lands, land rights and

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improvements associated therewith, the amount of (i) a bona fide written offer from an Outside Party ready, willing and able (subject to obtaining any required regulatory approvals) to purchase the Transfer Interest; or, in the absence of a bona fide written offer, (ii) a purchase price set out in a bona fide purchase and sale agreement between the Participant desiring to Assign and an Outside Party ready, willing and able (subject to obtaining any required regulatory approvals) to purchase the Transfer Interest; or

11.2.2 Where the Outside Party proposes to purchase from the Participant desiring to Assign, (i) as part of a non-monetary offer (such as in the case of an asset swap) or (ii) when a segregated value for the Transfer Interest is not available (such as in the case of a bundled or packaged sale of assets), or (iii) where the Outside Party proposes to purchase an interest not only in the San Juan Project and/or in contract rights, water rights, lands, land rights and improvements associated therewith, but also in other property of the Participant desiring to Assign, the purchase price shall be the fair market value of the Transfer Interest. As used herein, the term “fair market value” means the amount of money which a purchaser, willing but not obligated to buy the property, will pay to an owner, willing but not obligated to sell it, taking into consideration all of the uses to which the Transfer Interest is adapted and might in reason be applied.

11.3 At least three (3) months prior to its intended date to Assign, and after its receipt of a bona fide written offer, or execution of a bona fide purchase and sale agreement, of the type described in Section 11.2, the Participant desiring to Assign its Transfer Interest shall serve written notice of its intention to do so upon the Participant(s) having a right of

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first refusal, in accordance with Section 42. Such notice shall: (i) have attached as an exhibit a copy of the bona fide offer of an Outside Party or of the bona fide purchase and sale agreement between the Outside Party and the Participant desiring to Assign (an “Outside Offer”); and (ii) shall contain a statement of the approximate proposed date to Assign.

11.4 The Participants having the right of first refusal shall signify its (their) desire to purchase the entire Transfer Interest, or not purchase the entire Transfer Interest, by serving written notice of its (their) intention upon the Participant desiring to Assign pursuant to Section 42 within sixty (60) days after such service pursuant to Section 11.3 of the written notice of intention to Assign. Failure by a Participant to serve notice as provided hereunder within the time period specified shall be conclusively deemed to be notice of its intention not to purchase the Transfer Interest.

11.5 When intention to purchase the entire Transfer Interest has been indicated by notices duly given hereunder by the Participant(s) desiring to purchase the Transfer Interest, the affected Participants shall thereby incur the following obligations:

11.5.1 The Participant desiring to Assign and a Participant desiring to purchase the Transfer Interest shall be obligated to proceed in good faith and with diligence to obtain all required authorizations and approvals to Assign;

11.5.2 The Participant desiring to Assign shall be obligated to obtain the release of any liens imposed by or through it upon any part of the Transfer Interest and to Assign the Transfer Interest at the earliest practicable date thereafter; and

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11.5.3 A Participant desiring to purchase the Transfer Interest shall be obligated to perform all terms and conditions required of it to complete the purchase of the Transfer Interest.

The purchase of the Transfer Interest shall be fully consummated within six (6) months following the date upon which all notices required to be given under this Section 11 have been duly served, unless the Participant is then diligently pursuing applications to appropriate regulatory bodies (if any) for required authorizations to effect such assignment or is then diligently prosecuting or defending appeals from orders entered or authorizations issued in connection with such applications.

11.6 If the intention to purchase the entire Transfer Interest has not been indicated by notices given within the time periods specified in this Section 11 by a Participant desiring to purchase the Transfer Interest, the Participant desiring to Assign shall be free to Assign all, but not less than all, of its Transfer Interest to the Outside Party that made the Outside Offer, upon the terms and conditions set forth in the Outside Offer. If such assignment of the entire Transfer Interest to the Outside Party is not completed within three (3) years after the approximate proposed date to Assign specified in the notice given pursuant to Section 11.3, the Participant desiring to Assign its Transfer Interest must, unless it is then diligently pursuing its applications to appropriate regulatory bodies (if any) for required authorizations to effect such assignment, or is then diligently prosecuting or defending appeals from orders entered or authorizations issued in connection with such applications, give another complete new right of first refusal to the Participant(s) desiring to purchase pursuant to the provisions of this Section 11, before such Participant shall be free to Assign a Transfer Interest to said Outside Party.

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11.7 No assignment of a Transfer Interest, whether to another Participant or to an Outside Party, shall relieve the assigning Participant from full liability and financial responsibility for performance after any such assignment: (i) of all obligations and duties incurred by such Participant prior to such assignment under the terms and conditions of the Project Agreements; and/or (ii) of all obligations and duties provided and imposed after such assignment upon such assigning Participant under the terms and conditions of the Project Agreements, unless and until the assignee shall agree in writing with the remaining Participants to assume the obligations and duties of a Participant hereunder; provided further, however, that such assignor shall not be relieved of any of its obligations and duties by an assignment under this Section 11, without the express prior written consent of the remaining Participants, which consent shall not be unreasonably withheld.

11.8 Any transferee, successor or assignee, or any party who may succeed to the Transfer Interest pursuant to this Section 11, shall specifically agree in writing with the remaining Participants at the time of such transfer or assignment that it will not transfer or assign all or any portion of the Transfer Interest so acquired without complying with the terms and conditions of this Section 11.

11.9 The provisions of Section 11.8 shall not be applicable to any assignment of a Transfer Interest by one Participant to another Participant, provided that payment in full of such Transfer Interest, as defined in Section 11, has been made by the Participant who is the assignee thereof.

11.10 A Participant may, for the purpose of financing its interest in pollution control systems and facilities at the San Juan Project, sell, transfer or convey such interests pursuant to the New Mexico Pollution Control Revenue Bond Act, and any such sale,

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transfer or conveyance shall not be deemed as an assignment, transfer, conveyance or other disposal within the meaning of this Section 11.

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12.0 RIGHTS OF PNM AND TEP IN WATER AND COAL:

12.1 If, pursuant to the terms and conditions of the Underground Coal Sales Agreement, or the sublease dated August 18, 1980 (as amended to date and as such sublease may be amended from time to time), between Western Coal Company and Utah International, Inc. or their successors, PNM and TEP succeed to any interest in coal lands, coal leases, water rights, or other property, the rights, titles and interests of PNM and TEP therein shall be held as tenants in common, with each of PNM and TEP having an equal undivided one-half (1/2) interest therein, and such rights, titles and interests shall be subject to all the terms and conditions set forth and contained in this Agreement.

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13.0 SEVERANCE OF IMPROVEMENTS:

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PART III

ENTITLEMENTS TO OUTPUT OF SAN JUAN PROJECT

14.0 ENTITLEMENT TO CAPACITY AND ENERGY:

14.1 Subject to the provisions of Section 16, the Participants shall be entitled to the Net Effective Generating Capacity of each of Unit 1 and Unit 4 in proportion to their respective Participation Shares. Each Participant shall be entitled to schedule its Energy up to the Available Operating Capacity.

14.2 The Operating Agent shall keep the system dispatcher of each Participant advised of the Available Operating Capacity.

14.5 The Operating Agent shall, to the extent possible, generate Energy at the San Juan Project in accordance with schedules submitted by each Participant, as such schedules

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may be revised from time to time, as long as such schedules do not jeopardize the operation of the San Juan Project.

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15.0 CAPACITY ALLOCATION OF SWITCHYARD FACILITIES:

15.1.1 The transmission capacity of the FC Line shall be measured at the Four Corners terminal. PNM and TEP each shall be entitled to fifty percent (50%) of the designated FC Line Capacity.

15.1.2 The transmission capacity of the FC Line termination and other contract matters concerning the Four Corners Project shall be handled individually by PNM and TEP.

15.2 The points of attachment to the San Juan 345 kV Switchyard Facilities for the purposes of this Section 15 are:

No. 1: TEP/PNM No. 1 345 kV transmission line;

No. 2: TEP/PNM No. 2 345 kV transmission line;

No. 3: PNM/TEP Four Corners Generating Plant 345 kV switchyard (through the FC Line);

No. 4: PNM’s WW 345 kV transmission line;

No. 5: PNM’s OJ 345 kV transmission line;

No. 6: Colorado Public Service Company/Western Area Power Administration/Tri-State Rifle 345 kV transmission line;

No. 7: Western Area Power Administration-Shiprock 345 kV transmission line.

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15.2.1 The Participants collectively shall not schedule more Power and Energy through any of the foregoing individual points of attachment than the established rating of that facility.

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16.0 USE OF FACILITIES DURING CURTAILMENTS:

16.1 If the Net Effective Generating Capacity of Units 1 and 4 is reduced because of factors (including, but not limited to, equipment failures, scheduled or unscheduled outages, fuel or fuel deliveries, water supply, air quality limitations) which commonly influence the total output of such Units, each Participant’s entitlement to Capacity during such period shall be reduced in proportion to the percentages specified in Section 6.2.6 during each hour of such curtailment unless otherwise specified in a separate agreement.

16.3 [Omitted]

16.5 Curtailment of the transmission capacity in the Switchyard Facilities shall be allocated to the Participants in the manner and in the amounts as set forth in Section 6.2.7.

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16.6 No Participant shall exercise its rights relating to the San Juan Project so as to endanger or unreasonably interfere with the operation of the San Juan Project or the right of any other Participant to use its share of Capacity and Energy from the San Juan Project.

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17.0 START-UP AND AUXILIARY POWER AND ENERGY REQUIREMENTS:

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PART IV

ADMINISTRATION

18.0 COORDINATION COMMITTEE:

18.1 As a means of securing effective cooperation and interchange of information and of providing consultation on a prompt and orderly basis among the Participants in connection with various administrative and technical problems which may arise from time to time under this Agreement, the Coordination Committee shall remain in existence during the term of this Agreement. Except as otherwise expressly provided in this Agreement, the Coordination Committee shall have no authority to modify any of the provisions of this Agreement.

18.2 The Coordination Committee shall consist of one representative from each Participant who shall be an officer or other duly authorized representative of a Participant. Any of the Participants may designate an alternate or substitute to act as its representative on the Coordination Committee in the absence of the regular representative on the Coordination Committee or to act on specified occasions or with respect to specified matters. Each Participant shall notify the other Participants promptly, in writing, of the designation of its representative and alternate representative on the Coordination Committee and of any subsequent changes in such designations. The chairperson of the Coordination Committee shall be a representative employed by the Operating Agent.

18.3 The Coordination Committee shall have the following functions and responsibilities:

18.3.1 Provide liaison between and among the Participants.

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18.3.2 Exercise general supervision over the Engineering and Operating Committee, the Fuels Committee and the Auditing Committee.

18.3.3 Consider and act upon all matters referred to the Coordination Committee by the Engineering and Operating Committee, the Fuels Committee and the Auditing Committee.

18.4 Any action or determination of the Coordination Committee shall require a vote of the Participants in accordance with Sections 18.4.1, 18.4.2, 18.4.3 or 18.4.4. A Participant’s Coordination Committee representative shall be entitled to vote on all matters except those actions or determinations which relate solely to a Unit or to common property in which such Participant does not have a Participation Share or as provided in Section 35.4.1. If a Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majorities for actions or determinations specified in Sections 18.4.1, 18.4.2, 18.4.3 or 18.4.4 shall be adjusted in proportion to the number of Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII, attached hereto and incorporated herein. Maintenance scheduling and operation during periods of curtailment of the total San Juan Project are not matters which relate solely to a Unit, but are deemed to be matters affecting all Units.

18.4.1 Except as provided in Sections 18.4.2, 18.4.3 and 18.4.4, any actions or determinations brought before the Coordination Committee shall require the following vote:

(a) More than a sixty-six and two thirds percent (66 2/3%) majority of the Participation Shares of the Participants in a Unit or common property as defined in Section 6.2; and

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(b) More than a sixty-six and two thirds percent (66 2/3%) majority of the number of individual Participants having a Participation Share in a Unit or common property as defined in Section 6.2.

(a) More than an eighty-two percent (82%) majority of the Common Participation Shares of the Participants; and

(b) A minimum of sixty-six and two thirds percent (66 2/3%) majority of the number of the individual Participants.

(a) More than an eighty-two percent (82%) majority of the Common percentages of the Participants; and

(b) A minimum of sixty-six and two thirds percent (66 2/3%) majority of the number of individual Participants.

18.4.4 Any action or determination of the Coordination Committee regarding individual capital projects with a cost greater than fifty million dollars ($50,000,000) (“Large Capital Improvement”) shall require unanimous approval of the representatives on the Coordination Committee. Prior to presenting a capital budget item (“CBI”) for a Large Capital Improvement, the Operating

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Agent shall provide timely financial analysis to the Participants justifying the proposed capital expenditure for the Large Capital Improvement. If one or more of the Participants abstains from voting on the CBI for any Large Capital Improvement, approval of such CBI shall require the affirmative vote of all of the Participants that have voted.

18.5 The Coordination Committee shall keep written minutes and records of all meetings. Any action or determination made by the Coordination Committee shall be reduced to writing and shall become effective when signed by the representatives of the Participants entitled to vote thereon, representing a voting majority of the members of the Coordination Committee, as defined in Section 18.4; provided, however, in the event of an Operating Emergency, actions or determinations may be made on the basis of oral agreements among duly authorized representatives of the respective Participants entitled to vote thereon, and such action or determination subsequently shall be reduced to writing. Coordination Committee representatives may, by prior arrangement with the chairperson of the Coordination Committee, attend a meeting of the Coordination Committee by conference call or video conferencing. A Coordination Committee representative who is unable to attend a meeting of the Coordination Committee may vote in absentia by delivering to the chairperson of the Coordination Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

18.6 Except for matters subject to the voting requirements of Sections 18.4.3, 18.4.4 and 40A, in the event the Coordination Committee fails to reach agreement on any

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matter, which such committee is authorized to determine, approve or otherwise act upon after a reasonable opportunity to do so, then the Operating Agent shall be authorized and obligated to take such reasonable and prudent action, consistent with Prudent Utility Practice, as is necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree.

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19.0 ENGINEERING AND OPERATING COMMITTEE:

19.2 The Engineering and Operating Committee shall consist of up to two representatives from each Participant who shall collectively have one vote. Any of the Participants may designate an alternate or substitute to act as its representative on the Engineering and Operating Committee in the absence of a regular representative on the Engineering and Operating Committee or to act on specified occasions or with respect to specified matters. Each Participant shall notify the other Participants promptly, in writing, of the designation of its representatives and alternate representative on the Engineering and Operating Committee and of any subsequent change in the designation. The chairperson of the Engineering and Operating Committee shall be a representative employed by the Operating Agent.

19.3 The Engineering and Operating Committee shall have the following functions and responsibilities:

19.3.1 Review and approve the following items related to the performance of Operating Work.

19.3.1.1 Capital Improvements and the annual Capital Improvements budget.

19.3.1.2 The annual staffing table.

19.3.1.3 The annual operation and maintenance budget.

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19.3.1.4 Such written statements of operating or maintenance procedures as may be submitted to the Engineering and Operating Committee.

19.3.1.5 The planned annual maintenance schedule.

19.3.1.6 The policies for establishing the Emergency Spare Parts inventory.

19.3.1.7 The policies for establishing the inventory for Materials and Supplies.

19.3.1.9 The determination of Net Effective Generating Capacity, Minimum Net Generation and Net Energy Generation of the San Juan Project, based upon recommendations of the Operating Agent.

19.3.1.10 The principles and procedures for establishing communication channels among Participants.

19.3.1.11 The operating procedures for performance and efficiency testing.

19.3.1.12 The operating procedures for maintaining complete and accurate Capacity and Energy accounting.

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19.3.1.13 The Operating Agent’s estimate and analysis of the total expenditures resulting from an Operating Emergency, as provided in Section 29.7.

19.3.1.14 The results and expenditures of programs and contracts on environmental control and data collection for which the Operating Agent has contracted.

19.3.2 Establish procedures for the operation of the San Juan Project during any period of curtailed operations which reduces or may reduce the Net Effective Generating Capacity.

19.3.3 Except for an Operating Emergency, as provided in Section 29, designate a construction agent responsible for the design, construction and acquisition of Capital Improvements.

19.3.4 Approve the list of transportation and motorized equipment to be purchased or leased by the Operating Agent for use in the performance of Operating Work.

19.3.5 Perform such other functions and responsibilities as may be assigned to it from time to time by the Coordination Committee.

19.4 Any action or determination of the Engineering and Operating Committee shall require a vote of the Participants, in the manner provided for in Sections 18.4.1 and 18.4.2. A Participant’s Engineering and Operating Committee voting representative shall be entitled to vote on all matters except those actions or determinations which relate solely to a Unit or to common property in which such Participant does not have a Participation Share or as provided in Section 35.4.1. If a Participant’s right to vote has been suspended

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pursuant to Section 35.4.1, the requisite majorities for actions or determinations specified in Sections 18.4.1 and 18.4.2 shall be adjusted in proportion to the number of Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII. Maintenance scheduling and operation during periods of curtailment of the total San Juan Project are not matters which relate solely to a Unit, but are deemed to be matters affecting all Units.

19.5 The Engineering and Operating Committee shall keep written minutes and records of all meetings. Any action or determination made by the Engineering and Operating Committee shall be reduced to writing and shall become effective when signed by the representatives of the Participants entitled to vote thereon, representing a voting majority of the members of the Engineering and Operating Committee, as defined in Section 19.4; provided, however, in the event of an Operating Emergency, actions or determinations may be made on the basis of oral agreements among duly authorized representatives of the respective Participants entitled to vote thereon, and such action or determination subsequently shall be reduced to writing. Engineering and Operating Committee representatives may, by prior arrangement with the chairperson of the Engineering and Operating Committee, attend a meeting of the Engineering and Operating Committee by conference call or video conferencing. An Engineering and Operating Committee representative who is unable to attend a meeting of the Engineering and Operating Committee may vote in absentia by delivering to the chairperson of the Engineering and Operating Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

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19.6 In the event that less than a requisite majority of the Engineering and Operating Committee is obtained, the matter shall be referred to the Coordination Committee for decision upon the request of any Participant’s Engineering and Operating Committee representative.

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20.0 FUELS COMMITTEE:

20.1 As a means of establishing a centralized forum to facilitate the timely and candid consideration and discussion between all Participants of policies and issues associated with the procurement of coal for the San Juan Project, there is hereby established a Fuels Committee, which shall remain in existence during the term of this Agreement. The Participants do not intend that the operation of the Fuels Committee shall affect the day-to-day fuels-related operational responsibilities of the Operating Agent, except as otherwise specifically provided in this Section 20. The Fuels Committee shall have no authority to modify any of the provisions of this Agreement.

20.2 The Fuels Committee shall consist of one representative from each Participant. Any of the Participants may, by written notice to the other Participants, designate an alternate or substitute to act as its representative on the Fuels Committee in the absence of the regular representative on the Fuels Committee or to act on specified occasions or with respect to specified matters. Each Participant shall notify the other Participants promptly in writing of the designation of its representative on the Fuels Committee and of any subsequent change in such designation. The chairperson of the Fuels Committee shall be a representative employed by the Participant that is a signatory to the CSA. The Fuels Committee shall meet regularly, but in no event less than semiannually. Special meetings shall be called by the chairperson if requested in writing by any three (3) Participants.

20.3 Subject to Section 20.7, the Fuels Committee shall have the following functions and responsibilities:

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20.3.1.1 Annual fuel supply budgets

20.3.1.2 Coal cost

20.3.1.3 Coal delivery rates and minimum take obligations

20.3.1.4 Coal quality

20.3.1.5 Contract terms

20.3.1.6 Economic requirements

20.3.1.7 Negotiation strategies

20.3.1.8 Potential coal suppliers

provided, however, that prior to any such study being conducted, the Participant(s) desiring that the study be performed shall have made suitable arrangements therefor, including payment arrangements with the provider of the study. Nothing in this Section 20.3 shall be construed to require the Operating Agent or any Participant to undertake any uncompensated or unfunded study which it would not otherwise perform.

20.3.2 To obtain input from all Participants regarding individual criteria and economic requirements necessary to vote on matters entrusted to the Fuels Committee or to make collective recommendations to the Coordination Committee.

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20.3.3 To receive progress reports from and provide recommendations to negotiators acting on behalf of Participants in the negotiation and administration of coal supply and related agreements.

20.3.4 To provide regular progress reports to the Engineering and Operating and to the Coordination Committees, as requested by such committees.

20.3.5 To establish the amount of coal to be maintained in the Emergency Coal Storage Pile.

20.3.6 To establish operating procedures for delivery of coal to the Emergency Coal Storage Pile.

20.3.7 To establish procedures for the determination of Participant Coal Consumption.

20.3.8 To perform such other functions and responsibilities as may be assigned to it from time to time by the Coordination Committee.

20.4 The following special procedures shall apply to all negotiations or discussions with SJCC regarding amendment, interim pricing agreements, termination or succession of the CSA, related agreements, or with any other coal supplier or potential supplier. No Fuels Committee representative or Participant shall engage in bilateral negotiations or discussions concerning coal supply or related matters for the San Juan Project with SJCC or any other coal supplier or potential supplier; provided, however, that nothing herein shall be construed to prevent the Operating Agent or the Participant which is a signatory to the CSA, in the conduct of its day-to-day operational responsibilities, from performing Operating Work, engaging in business contacts and

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communications with SJCC or other coal suppliers or potential suppliers to the San Juan Project or in the administration of the CSA and related agreements.

20.4.1 The Participant which is a signatory to the CSA shall be entitled to have at least two (2) representatives present at any such negotiations or discussions. Participants not signatories to the CSA or its successors shall have the collective right to have two (2) representatives present at any such negotiations or discussions. The non-signatory Participants may jointly or separately designate representatives, but in no case may the total number of representatives so designated by all of the non-signatory Participants exceed two (2). Any dispute among the non-signatory Participants regarding the naming of representatives shall be subject to resolution pursuant to Section 37 and shall not restrict the rights of any other representatives to engage in any ongoing negotiations or discussions. Representatives shall be designated in writing by the Participant which is a signatory to the CSA and non-signatory Participants. If such representatives are not employees of a non-signatory Participant, such fact shall be disclosed in writing to all Participants. Representatives shall agree in writing to: (i) avoid any conflict of interest that would be detrimental to the operation of the San Juan Project; and (ii) maintain all proprietary information obtained through such negotiations and discussions in confidence. The form of such confidentiality agreements shall be prepared by the Fuels Committee, and shall be subject to the approval of the Participant that is a signatory to the CSA, such approval not to be unreasonably withheld. Such confidentiality agreements shall be executed by a non-signatory Participant’s Coordination Committee representative or, as

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appropriate, the person authorized by such non-signatory Participant or Representative to execute such documents. Representatives may be changed by non-signatory Participants by the giving of written notice to all other Participants.

20.5 Any proposed action or determination regarding any amendment of the CSA, replacement of the CSA with a new agreement or any interim or other annual coal pricing agreement related to the CSA (or its successor) or any other action or determination of the Fuels Committee shall be submitted to the vote of the representatives on the Fuels Committee. Any such action or determination shall require the affirmative vote as established in Section 18.4.3, except that if a Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majority for actions or determinations specified in Section 18.4.3 shall be adjusted in proportion to the number of Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII.

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in accordance with Section 18.4.3. If the requisite majorities are obtained in the Coordination Committee vote, the Participant which is a signatory to the CSA then in effect or the Operating Agent, as applicable, shall proceed in accordance with the affirmative vote of the Coordination Committee.

20.6 The Fuels Committee shall keep written minutes and records of all meetings. Any action or determination made by the Fuels Committee shall be reduced to writing and shall become effective when signed by the representatives of the Participants representing a voting majority. Fuels Committee representatives may, by prior arrangement with the chairperson of the Fuels Committee, attend a meeting of the Fuels Committee by conference call or video. A Fuels Committee representative who is unable to attend a meeting of the Fuels Committee may vote in absentia by delivering to the chairperson of the Fuels Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

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agreement for the performance of reclamation services for disturbance of the SJCC Site Area. To the extent of any conflict between this Section 20 and the Mine Reclamation Agreement, the provisions of the Mine Reclamation Agreement shall control.

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21.0 AUDITING COMMITTEE:

21.1 The Auditing Committee shall remain in existence during the term of this Agreement. The Auditing Committee shall have no authority to modify any of the provisions of this Agreement.

21.2 The Auditing Committee shall consist of one representative from each Participant. Any of the Participants may designate an alternate or substitute to act as its representative on the Auditing Committee in the absence of the regular representative on the Auditing Committee or to act on specified occasions or with respect to specified matters. Each Participant shall notify the other Participants promptly, in writing, of the designation of its representative and alternate representative on the Auditing Committee and of any subsequent changes in such designation.

21.3 The Auditing Committee shall have the following functions and responsibilities under this Agreement:

21.3.2 Review and approve the format and content of the Operating Agent’s accounting records and reports for Operating Work and Capital Improvements.

21.3.3 Certify to the Participants, for management purposes and for the use of the Participants only, that the Operating Agent’s results of operations and

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accounting methods and records, including any allocations for Operating Work and Capital Improvements, are in accordance with the Project Agreements and Accounting Practice.

21.3.4 Review and make recommendations to the Coordination Committee regarding a Participant’s administrative and general expense allowance and other normal loadings when such Participant acts as construction agent for Capital Improvements.

21.3.5 Review and approve the Operating Agent’s cost and expense allocations between (i) electric generation and related functions and (ii) unrelated functions.

21.3.6 Advise and make recommendations to the Coordination Committee and Operating Agent on matters involving auditing and financial transactions.

21.3.7 Develop procedures for proper accounting and financial liaison between Participants in connection with the Operating Work and Capital Improvements.

21.3.8 Perform such functions and responsibilities as may be assigned to it from time to time by the Coordination Committee or as otherwise provided in this Agreement.

21.4 Any action or determination of the Auditing Committee shall require a vote of the voting Participants in accordance with Section 18.4.1. A Participant’s Auditing Committee representative shall be entitled to vote on all matters except those actions or determinations which relate solely to a Unit or common property in which such Participant does not have a Participation Share except that if a Participant’s right to vote has been

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suspended pursuant to Section 35.4.1, the requisite majority for actions or determinations specified in Section 18.4.1 shall be adjusted in proportion to the number of Participants whose right to vote has not been suspended. An example of such an adjustment is provided in Exhibit VIII.

21.5 The Auditing Committee shall keep written minutes and records of all meetings, and any action or determination by the Auditing Committee shall be reduced to writing and shall become effective when signed by the representatives of the Participants entitled to vote thereon, representing a voting majority of the members of the Auditing Committee. Auditing Committee representatives may, by prior arrangement with the chairperson of the Auditing Committee, attend a meeting of the Auditing Committee by conference call or video conferencing. An Audit Committee representative who is unable to attend a meeting of the Audit Committee may vote in absentia by delivering to the chairperson of the Audit Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.

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necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree.

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PART V

BUDGETS AND OPERATING EXPENSES

22.0 OPERATION AND MAINTENANCE EXPENSES:

22.1.1 For Unit 1 and for all equipment and facilities directly related to Unit 1 only, in accordance with the following percentages:

22.1.1.1 PNM - 50 percent

22.1.1.2 TEP - 50 percent

22.1.1.3 [Omitted]

22.1.1.4 Farmington - 0 percent

22.1.1.5 [Omitted]

22.1.1.6 LAC - 0 percent

22.1.1.7 [Omitted]

22.1.1.8 [Omitted]

22.1.1.9 UAMPS - 0 percent

22.1.1.10 PNMR-D – 0 percent

22.1.2 [Omitted]

22.1.3 For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:

22.1.3.1 PNM - 64.482 percent

22.1.3.2 TEP - 0 percent

22.1.3.3 [Omitted]

22.1.3.4 Farmington - 8.475 percent

22.1.3.5 [Omitted]

22.1.3.6 LAC - 7.20 percent

22.1.3.7 [Omitted]

22.1.3.8 [Omitted]

22.1.3.9 UAMPS - 7.028 percent

22.1.3.10 PNMR-D – 12.815 percent

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22.1.4 For equipment and facilities common to Units 1 and 2 only, in accordance with the following percentages:

22.1.4.1 PNM - 50 percent

22.1.4.2 TEP - 50 percent

22.1.4.3 [Omitted]

22.1.4.4 Farmington - 0 percent

22.1.4.5 [Omitted]

22.1.4.6 LAC - 0 percent

22.1.4.7 [Omitted]

22.1.4.8 [Omitted]

22.1.4.9 UAMPS - 0 percent

22.1.4.10 PNMR-D – 0 percent

22.1.5 For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:

22.1.5.1 PNM - 64.482 percent

22.1.5.2 TEP - 0 percent

22.1.5.3 [Omitted]

22.1.5.4 Farmington - 8.475 percent

22.1.5.5 [Omitted]

22.1.5.6 LAC - 7.20 percent

22.1.5.7 [Omitted]

22.1.5.8 [Omitted]

22.1.5.9 UAMPS - 7.028 percent

22.1.5.10 PNMR-D – 12.815 percent

22.1.6 For the Switchyard Facilities except as otherwise provided in Section 15, in accordance with the following percentages:

22.1.6.1 PNM - 65 percent

22.1.6.2 TEP - 35 percent

22.1.6.3 [Omitted]

22.1.6.4 Farmington - 0 percent

22.1.6.5 [Omitted]

22.1.6.6 LAC - 0 percent

22.1.6.7 [Omitted]

22.1.6.8 [Omitted]

22.1.6.9 UAMPS - 0 percent

22.1.6.10 PNMR-D – 0 percent

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22.1.7.1 PNM - 62.708 percent

22.1.7.2 TEP - 19.8 percent

22.1.7.3 [Omitted]

22.1.7.4 Farmington - 3.679 percent

22.1.7.5 [Omitted]

22.1.7.6 LAC - 3.123 percent

22.1.7.7 [Omitted]

22.1.7.8 [Omitted]

22.1.7.9 UAMPS - 3.017 percent

22.1.7.10 PNMR-D – 7.673 percent

If the term of this Agreement is extended beyond June 30, 2022, then the percentages shown in Section 6.2.6 (as modified by any transfers pursuant to Sections 40A or 40B) shall apply after June 30, 2022 in lieu of the percentages set forth in this Section 22.1.7.

22.1.8 In the event of a permanent shutdown of Unit 1 prior to the permanent shutdown of Unit 4, the expenses incurred in connection with the shutdown (which may include removal, salvage, cleanup and protection service) shall be allocated as set forth in Section 22.1.1. In the event of a permanent shutdown of Unit 4 prior to the permanent shutdown of Unit 1, said expenses shall be allocated as set forth in Section 22.1.3. Expenses which are attributable to equipment and facilities common to more than one Unit shall be apportioned in accordance with Section 22.1, as applicable. Expenses incurred under this Section

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22.1.8 shall be minimized insofar as reasonably practicable, and any expenses paid by a Participant under this Section 22.1.8 that would otherwise qualify as costs of initial or interim Decommissioning Work under Sections 4.1 and 4.2 of the Decommissioning Agreement shall be credited against the Participants’ cost responsibilities under the Decommissioning Agreement.

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22.2 O&M Expenses chargeable to the following FERC Accounts shall be apportioned among the Participants in accordance with Sections 22.1.1, 22.1.2, 22.1.3, 22.1.4, 22.1.5 and 22.1.7, as applicable:

22.2.2 Administrative and General Expenses directly chargeable to FERC Accounts 920, 921, 923, 926, 930.2, 931 and 935, by on-site San Juan Project employees and by A&G related departments located off-site as set forth in Exhibit VI, Attachment A, which have not been included as a part of the A&G Ratio or charged to FERC Account 935, in accordance with Section 22.4. Such direct A&G charges must be supported by the Operating Agent and are subject to audit and approval by the Auditing Committee. If the Auditing Committee is unable to agree on the appropriateness of direct A&G charges, the Auditing Committee shall submit the entire matter to the Coordination Committee.

22.2.3 O&M Expenses chargeable to FERC Account 501 shall be apportioned among the Participants in accordance with Section 23.

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22.2.5 Costs or revenues chargeable to the following FERC Operating and Non-Operating Accounts: 411.8, 411.9, 412, 421 and 426.

22.4 The O&M Expenses for the Switchyard Facilities chargeable to FERC Accounts 560 through 573 and FERC Account 935 shall be apportioned among the Participants in accordance with Section 22.1.6.

22.6.1 If any Participant believes that the method used in determining A&G Ratio, Payroll Tax Ratio, Injuries and Damages Ratio and Pension and Benefits

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Ratio, in accordance with Exhibit VI (Attachments A, B, C and D thereto), results in an unreasonable burden on such Participant(s), such Participant(s) may request that said method used in determining said ratios be submitted to the Auditing Committee for review. After any such request, the Auditing Committee shall review said method and shall endeavor to agree upon whether or not said unreasonable burden does actually exist. If, after such review, the Auditing Committee determines that the application of said method does result in an unreasonable burden on the Participant, the Auditing Committee shall determine and recommend a modified method to the Coordination Committee to eliminate such unreasonable burden. If, after such review, the Auditing Committee is unable to agree upon whether or not such unreasonable burden does exist or is unable to agree on a modified method for eliminating said unreasonable burden, the Auditing Committee shall submit the entire matter to the Coordination Committee.

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eliminate such unreasonable burden, upon request of a Participant, either matter may be submitted to arbitration pursuant to Section 37.

22.9 The Operating Agent shall bill to the requesting Participant(s) the costs and expenses, including A&G expenses, incurred by the Operating Agent (including, but not limited to, fees of outside legal counsel or consultants, time of in-house legal counsel and other employees and agents of the Operating Agent) in performing tasks requested by a Participant in relation to (i) the offering or sale of bonds or other type of security by a

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Participant in connection with the acquisition or ownership of an interest in the San Juan Project; and (ii) the attempted or contemplated sale by a Participant of any portion of its ownership interest in the San Juan Project. The Operating Agent shall establish and maintain appropriate accounting procedures to identify such costs and expenses incurred by the Operating Agent.

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23.0 FUEL COSTS:

23.1 The quantity of coal delivered to the San Juan Project shall be determined by the belt scales, in accordance with the CSA.

23.3 [Omitted]

23.4 [Omitted]

23.6 All other fuel-related expenses which are chargeable to FERC Account 501 shall be apportioned among and paid for by the Participants on the following basis:

23.6.2 Fixed fuel-related expenses (including, but not limited to fuel handling) on the basis of Common Participation Share.

23.6.3 Fuel oil purchased for use at the San Juan Project is first delivered into one of two storage tanks. Tank 1 and 2 storage tank feeds Unit 1 and Tank 3 and 4 storage tank feeds Unit 4. When oil is withdrawn from a storage tank for

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consumption, it is metered by Unit. Costs for fuel oil usage shall be separately accounted for by these two storage tanks as follows:

23.6.3.1 Costs for fuel oil purchases to Tank 1 and 2 shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Unit 1 Participants on the basis of Section 6.2.4. Monthly cost for fuel oil withdrawn from Tank 1 and 2 shall be credited to FERC Account 151 and charged to FERC Account 501 on an average price basis as determined by dividing the total number of gallons of fuel oil in Tank 1 and 2 at the beginning of the month, plus the fuel oil delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per gallon so derived by the number of gallons withdrawn from Tank 1 and 2. The cost for fuel oil withdrawn from Tank 1 and 2 charged to FERC Account 501 shall be apportioned among and paid for by the Unit 1 Participants first on the basis of the individual Unit metered consumption and then on the basis of Section 6.2.1. The cost for fuel oil withdrawn from Tank 1 and 2 thusly credited to FERC Account 151 shall be apportioned among the Unit 1 Participants on the basis of Section 6.2.4.

23.6.3.2 Costs for fuel oil purchases to Tank 3 and 4 shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Unit 4 Participants on the basis of Section 6.2.5. Monthly cost for fuel oil withdrawn from Tank 3 and 4 shall be credited to FERC Account 151 and charged to FERC Account 501 on an average price basis as determined by dividing the total number of gallons of fuel oil in

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Tank 3 and 4 at the beginning of the month, plus the fuel oil delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per gallon so derived by the number of gallons withdrawn from Tank 3 and 4. The cost for fuel oil withdrawn from Tank 3 and 4 charged to FERC Account 501 shall be apportioned among and paid for by the Unit 4 Participants first on the basis of the individual Unit metered consumption and then on the basis of Section 6.2.3. The cost for fuel oil withdrawn from Tank 3 and 4 thusly credited to FERC Account 151 shall be apportioned among the Unit 4 Participants on the basis of Section 6.2.5.

23.7 The Operating Agent shall provide the Participants a monthly written report on the following items related to coal deliveries at the San Juan Project:

23.7.1 [Omitted]

23.7.2 [Omitted]

23.7.3 Total actual coal deliveries by SJCC to the San Juan Project for each month and for the year to date.

23.7.4 Total actual coal deliveries to the San Juan Project for each month and for the year to date, allocated to the Participants.

23.7.5 Total cost and tonnage of inventory allocated to the Participants.

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23.11 In the event of a catastrophic occurrence which results in a sustained outage of a Unit and a determination that an “Uncontrollable Force” exists under the CSA, then in such event, FERC Account 151 will be allocated to the operable and non-operable Units. The portion of FERC Account 151 allocated to the non-operable Unit shall remain frozen until such time as such Unit is restored to operable condition. New costs of coal chargeable to FERC Account 151 will be apportioned among the Participants on the basis of the Participants’ Participation Shares in the generating capacity of the operable Unit. At such time as a damaged Unit is restored to operable condition, the frozen portion of Account 151 will be merged into the operable Unit’s portion of Account 151 and to the extent that a Participant is adversely impacted by an incremental increase in the average unit cost of coal an allocation of such incremental cost will be made and the net difference paid by the Participant having a credit balance.

23.12 The accounting practices and billing and accounting principles as stated in this Section 23 are applicable at the present time. If, however, at a later time these practices

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or principles are proven to be inadequate or other practices or principles later prove to be more equitable in the opinion of the Auditing Committee, the Coordination Committee, upon the recommendation of the Auditing Committee, may authorize changes and revisions to such practices and principles.

23.14 Beginning on January 1, 2018, PNM will supply coal to the Participants under the provisions of Section 23.18.

23.15 [Omitted]

23.16 [Omitted]

23.17 [Omitted]

23.18 SJCC will invoice PNM monthly as provided under the CSA. PNM will invoice each Participant monthly by Coal Tonnage Component and such Coal Tonnage Component will be paid for as follows:

23.18.1 Pre-existing Stockpile Coal tons as invoiced by SJCC will be allocated by a Participant’s Common Participation Share as of the Effective Date and will be paid for by each Participant at the price per ton charged by SJCC in its monthly invoicing to PNM.

23.18.2 Each year, PNM will develop a monthly Tier 1 Tonnage Allocation schedule with SJCC in the annual operating plan process as provided

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for in Section 7.2 of the CSA. With input from the Participants, PNM will develop a monthly allocation by Participant of such Tier 1 Tons (such individual allocation, its “Tier 1 Tonnage Allocation”). Such monthly Tier 1 Tonnage Allocation will be paid for by Participants whether or not their Participant Coal Consumption exceeded their Tier 1 Tonnage Allocation in the month. Monthly, for each Participant, its Tier 1 Tonnage Allocation, net of its invoiced Pre-existing Stockpile Coal for such month will be paid for at the then existing price for Tier 1 Tons under the CSA. In each of 2018 and 2019, two million eight hundred thousand (2,800,000) tons will be allocated by Participant Share. In each of 2020 and 2021, two million eight hundred thousand (2,800,000) tons will be allocated by Participant Share, and then PNM’s allocation will be reduced by one hundred fifty thousand (150,000) tons in each of those years. In 2022, one million four hundred thousand (1,400,000) tons will be allocated by Participant Share.

23.18.3 To the extent that a Participant’s Participant Coal Consumption in a month exceeds its Tier 1 Tonnage Allocation for such month, PNM will invoice such Participant such excess as Tier 2 Tons to be paid for at the then existing price for Tier 2 Tons under the CSA.

23.18.4 Legacy Costs as invoiced monthly by SJCC will be allocated using a Participant’s Common Participation Share for that year.

23.18.5 Cost for SJCC’s reclamation bond premium invoiced through the CSA will be allocated using a Participant’s Common Participation Share for that year.

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23.18.6 Weight-based taxes will be applied to the tonnages as invoiced by PNM to each Participant at the then-existing rates applicable to SJCC invoices.

23.18.7 Revenue-based taxes and royalties will be applied to the tonnages and total coal costs as invoiced by PNM to each Participant at the then-existing rates applicable to SJCC invoices.

23.18.8 In the event of an SJCC environmental force majeure, then Available Pre-existing Stockpile Tons will be allocated in the same manner as Pre-existing Stockpile Coal tons, and Force Majeure Tons will be allocated in the same manner as Tier 1 Tons unless otherwise approved by the Participants in the Fuels Committee. Such calculations will be on an annual basis.

23.18.9 Any other costs billed by SJCC under the CSA and not specifically addressed in this Section 23.18 will be apportioned among and paid for by the Participants on the basis of the Participant’s Common Participation Share for that year unless otherwise annually approved by the Participants in the Fuels Committee.

23.18.10 Annual Year-End Reconciliation Process.

23.18.10.1 At the end of each year, the Operating Agent will reconcile the sum of each Participant’s monthly CSA-related payments to a properly allocable share of annual Tier 1 Tons, Tier 2 Tons, Pre-existing Stockpile Coal tons, and cost associated with any change in Project Coal Inventory and invoice or refund any such reconciliation amounts to each Participant.

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23.18.10.2 Any net consumption of Project Coal Inventory tons will be charged to FERC Account 501 and apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s annual Tier 2 Tons after the reconciliation process bears to the total annual Tier 2 Tons consumption after the reconciliation process for all Units. The price for such tons will be determined by dividing the total recorded cost in FERC Account 151 by the total number of tons of coal in Project Coal Inventory, both as recorded on January 1 of said year. The total amount of any such payment for consumed Project Coal Inventory tons will subsequently be credited to FERC Account 151 and apportioned to the Participants based on the Participant’s Common Participation Share for that year.

23.18.10.3 The costs of any net addition to Project Coal Inventory tons, as invoiced by SJCC, will be charged to FERC Account 151 and apportioned to and paid for by the Participants based on the Participant’s Common Participation Share for that year.

23.18.10.4 If, at the end of any year, the Operating Agent has collected amounts in excess of those due SJCC under the CSA, such over-collection will be refunded to the Participants. The refund to each Participant will be an amount equal to the total amount of the over-collection multiplied by the tons each Participant’s Coal Consumption was less than its total annual Tier 1 Tonnage Allocation divided by the total

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amount by which all such Participants’ Coal Consumption was less than their Tier 1 Tonnage Allocation.

23.19 The cost of evaluating a long-term fuel supply for the San Juan Project, approved pursuant to a resolution of the Coordination Committee of May 23, 2014, shall be shared among the Participants in accordance with the following percentages:

23.19.1 PNM - 62.708 percent

23.19.2 TEP - 19.8 percent

23.19.3 Farmington - 3.679 percent

23.19.4 LAC - 3.123 percent

23.19.5 UAMPS - 3.017 percent

23.19.6 PNMR-D – 7.673 percent

To the extent that the cost of evaluating a long-term fuel supply for the San Juan Project has been invoiced and paid at a different percentage allocation than that set forth immediately above, the Participants agree to a true-up of the over- or under-payment to these percentages as of the Effective Date.

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24.0 ANNUAL BUDGETS:

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25.0 PAYMENT OF TAXES:

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26.0 MATERIALS AND SUPPLIES:

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26.7 A separate Materials and Supplies account and undistributed stores expense account will be established by the Operating Agent in accordance with FERC Accounts. Such charges and credits so allocated to Materials and Supplies shall be allocated to the Participants as a component of operation and maintenance expense in accordance with Section 22, or as a Capital Improvement in accordance with Section 7, as the case may be.

26.8 The inventory value of any item withdrawn from or returned to Materials and Supplies shall be the average cost of like items in inventory.

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27.0 EMERGENCY SPARE PARTS:

27.3 Emergency Spare Parts shall be owned by and the costs thereof shall be allocated between the Participants in accordance with their respective Participation Shares.

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PART VI

OPERATING AGENT

28.0 OPERATION AND MAINTENANCE:

28.1 PNM is the Operating Agent, unless replaced in accordance with Section 33.

28.2 All Participants hereby appoint PNM as their agent, and PNM agrees to undertake, as the agent of the Participants and as principal on its own behalf, the responsibility for the performance of Operating Work in accordance with this Agreement.

28.3 Subject to the provisions, conditions, limitations and restrictions of this Agreement, the Operating Agent shall:

28.3.1 Perform the Operating Work in accordance with the Project Agreements and Prudent Utility Practice.

28.3.2 Contract for, furnish or obtain the services and studies necessary for performance of Operating Work.

28.3.3 Arrange for the placement and maintenance of Operating Insurance.

28.3.4 Execute all contracts in the name of the Operating Agent, acting as principal on its own behalf and as agent for the Participants, in connection with the performance of Operating Work.

28.3.5 Furnish and train the necessary personnel for performance of Operating Work.

28.3.6 Have the coal replaced which has been removed from the Emergency Coal Storage Pile at the earliest practical time following resumption of normal coal deliveries.

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28.3.7 Enforce and comply with all contracts entered into for the performance of Operating Work.

28.3.8 Comply with any and all laws and regulations applicable to the performance of Operating Work.

28.3.9 Maintain the Operating Account and expend the Operating Funds only in accordance with this Agreement.

28.3.12 Recommend minimum notification times and lead times for changing scheduled Energy required for the Participants to the Engineering and Operating Committee for its approval.

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28.3.13 Act as operating representative or agent in connection with the administration and enforcement of the CSA and the CCRDA.

28.3.17 Provide the Auditing Committee with all accounting records, information, reports and other records relating to Operating Work, which may be necessary to permit such committee to perform its responsibilities under this Agreement.

28.3.19 Keep the Participants fully and promptly advised of material changes in conditions or other material developments affecting the performance of

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Operating Work and furnish the Participants with copies of any notices given or received pursuant to the Project Agreements.

28.3.20 Present claims to any insurer for losses and damages covered by valid and collectible Operating Insurance procured by the Operating Agent directly from the insurer. Investigate, adjust, settle, decline and defend claims against the Participants arising out of the performance of Operating Work when said claims or portions thereof are not covered by valid and collectible Operating Insurance; provided that the Operating Agent shall obtain the agreement of the Participants, acting through the Coordination Committee, prior to disposing of any claims or combination of claims arising out of the same occurrence which exceeds one hundred thousand dollars ($100,000).

28.3.21 Assist, as requested, other Participants and their insurers in the investigation, adjustment and settlement of any loss or claim arising out of Operating Work for which payment may be made on account of valid and collectible additional insurance applicable thereto procured by any such Participant; provided, that the Operating Agent may agree (by separate agreement) that a Participant procuring any policy or policies of additional insurance shall have the authority and the responsibility to (i) present, investigate, adjust, settle, decline and defend claims or potential claims covered by said policies in favor of the Participants and against any one or more of said insurers; and (ii) present, investigate, adjust, settle, decline and defend claims against the Participants arising out of the performance of Operating Work when said claims or portions thereof are not covered by said policies; and provided further, that such Participant shall obtain

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the agreement of the Participants, acting through the Coordination Committee, prior to the settlement of any claim or combination of claims arising out of the same occurrence which exceeds one hundred thousand dollars ($100,000).

28.3.22 Notwithstanding anything in Section 28.3.20 and 28.3.21 to the contrary, any Participant may at any time, at its own expense, employ its own counsel to assist in investigating, adjusting, settling, declining and defending claims of the types referred to in Sections 28.3.20 and 28.3.21 and the Operating Agent and its employees and counsel shall cooperate fully with such counsel and permit such counsel to participate fully in all of the foregoing activities.

28.3.23 Keep the Participants fully and promptly informed of any known default under the Project Agreements.

28.3.24 Determine switching and clearance procedures to be followed by the Participants at the San Juan Project.

28.3.25 Determine Available Operating Capacity from time to time and make recommendations to the Engineering and Operating Committee regarding items referenced in Section 19.3.1.9.

28.3.26 Upon the request of a Participant, provide such Participant, in reasonable quantity without direct charge therefor, a copy or copies of any report, record, list, budget, manual, accounting or billing summary, classification of accounts, or other documents or revisions of any of the foregoing items, all as prepared in accordance with this Agreement.

28.3.27 In the event of the failure of the Participant which is a signatory to the CSA then in effect to reach agreement on a matter described in Sections 18.7

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and 20.5.3, maintain a supply of coal to the San Juan Project, consistent with Prudent Utility Practice.

28.3.28 Manage the activities of the “designated representative” pursuant to the DR Agreement.

28.3.29 Perform all of the duties and obligations set out in this Agreement as duties and obligations of the Operating Agent.

28.4 The Participants shall lend and be properly reimbursed for all necessary and available assistance as may be requested by the Operating Agent in the performance of Operating Work.

28.5 The Operating Agent shall be the agent of the Participants and shall exercise only such authority as is conferred upon it by this Agreement. The Operating Agent shall not receive any fee or profit hereunder, unless otherwise agreed unanimously by the Participants.

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29.0 OPERATING EMERGENCY:

29.4 In the event the Operating Agent determines that the estimated amount required to terminate the Operating Emergency exceeds the amount which it is authorized to expend, the Operating Agent shall immediately notify the affected Participants following such determination. The Operating Agent shall provide the following information:

29.4.1 The estimated date when the Operating Emergency can be terminated.

29.4.2 The person or persons who would perform the work and furnish the materials required to terminate the Operating Emergency.

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29.4.3 The estimated amount of overtime, if any, which would be necessary in order to expedite the termination of the Operating Emergency.

29.4.4 The costs that are proposed to be capitalized, and salvage realized.

29.4.5 The costs that are proposed to be charged as maintenance expense.

29.4.6 The proposed administrative and general expense allowance applicable to such repair or reconstruction.

29.4.7 Such other information as may be necessary and required by the Engineering and Operating Committee to determine the manner in which the Operating Emergency is to be terminated.

29.5 The Engineering and Operating Committee shall review and approve the proposed repair or reconstruction, including the estimated cost thereof or shall agree upon an alternative.

29.6 Costs incurred in terminating an Operating Emergency may be billed to the Participants by the Operating Agent on the basis of its estimate of such costs with adjustment to be made in accordance with Section 29.8 when final cost determination has been made.

29.7 Following the termination of the Operating Emergency, the Operating Agent shall submit to the Participants a report containing a summary of the costs incurred and expenditures made in connection with the repair or reconstruction and such other information as may be required by the Engineering and Operating Committee.

29.8 The Operating Agent shall allocate to the Participants the costs incurred or expenditures made in such repair or reconstruction, as follows: (i) costs charged as

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maintenance expense, in accordance with Section 22; and (ii) any other such repair or reconstruction costs, in accordance with Section 7.

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30.0 PAYMENT OF EXPENSES BY PARTICIPANTS:

30.1 All amounts required to be advanced by the Participants in accordance with this Agreement shall be made payable to the Operating Account established by the Operating Agent. The Operating Funds shall be owned by the Participants in proportion to their respective balances therein at any given time, and the Operating Agent in its capacity as such shall not have any right or title therein except to maintain custody of and to disburse the Operating Funds as a conduit between the Participants and those to whom such disbursements shall be made.

30.2 The Engineering and Operating Committee shall establish a minimum amount for the Operating Funds which will be available to pay for expenditures or obligations incurred by or on behalf of the Participants in accordance with this Agreement. Such minimum amount of Operating Funds may be revised by the Engineering and Operating Committee at any time. The minimum amount of the Operating Funds and any increases therein shall be advanced by the Participants in accordance with the percentages set forth in Section 22, and shall be due and payable within fifteen (15) business days following notification of the establishment of the minimum amount to be kept in Operating Funds or the date on which any increase in such amount authorized by the Engineering and Operating Committee shall become effective. In the event the Engineering and Operating Committee decreases such minimum amount, then each Participant shall receive a credit which shall be equal to the product of its percentage, as set forth in Section 22, and the amount of any such decrease.

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30.3 Each Participant shall advance Operating Funds on the basis of notices (hereinafter called bills) submitted by the Operating Agent reflecting such Participant’s share of costs and expenses in accordance with this Agreement, as follows:

30.3.1 Expenses described in Sections 30 and 22 shall be billed in writing as follows:

30.3.1.1 The payroll costs to be paid to the Operating Agent’s employees for each pay period.

30.3.1.2 On the 20th day of each month, the total expenses incurred the previous month and described in Section 22 less those expenses billed under Section 30.3.1.1.

30.3.2 Bills submitted under Section 30.3.1 shall be due and payable within seven (7) business days following receipt of the bill.

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30.4 Except as expressly provided herein, nothing in this Agreement shall be deemed to require the Operating Agent to advance its own monies on any other basis than in its role, if any, as a Participant.

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31.0 OPERATING INSURANCE:

31.2 Except for Operating Insurance described in Sections 31.1.3 and 31.1.4, each Participant shall be a named insured individually and jointly and in accordance with its

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Participation Share as established in Section 6. Operating Insurance referred to in Section 31.1.1 shall carry cross-liability coverage.

31.3 In the event that another Participant’s insurance program affords equal or better coverage on a more favorable cost basis than that available to the Operating Agent, the Participants may agree (by separate agreement) that such insurance program may be utilized to afford all or part of the insurance coverage required by Section 31.1.

31.4.1 Any deductibles shall be shared by the Participants in accordance with the percentages established in Section 22.1.

31.5 The Operating Agent shall furnish each of the Participants with either a certified copy of each of the policies of Operating Insurance or a certified copy of each of the policy forms of Operating Insurance, together with a line sheet therefor (and any subsequent amendments) naming the insurers and underwriters and the extent of their participation. When the policies or policy forms of Operating Insurance have been approved in writing by all of the Participants, said policies or policy forms shall not be modified or changed by any Participant without the prior written consent of all of the Participants, except for minor and insubstantial changes or modifications, as to which notification shall be given by the Operating Agent to the Participants.

31.6 Each of the Operating Insurance policies shall be endorsed so as to provide that all named insureds shall be given thirty (30) days notice of cancellation or material change.

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31.7 Operating Insurance policies shall be primary insurance for all purposes and shall be so endorsed. Any insurance carried by a Participant individually shall not participate with the Operating Insurance as respects any loss or claim for which valid and collectible Operating Insurance shall apply. Such other insurance shall apply solely as respects the individual interest of the Participant carrying such other insurance.

31.8 Nothing herein shall prohibit the Operating Agent or any Participant from furnishing a policy of Operating Insurance which combines the coverage required by this Agreement with coverage outside the scope of that required by this Agreement. If the Operating Agent or any Participant furnishes a policy of Operating Insurance which combines the coverage required by this Agreement with coverage outside the scope of that required by this Agreement, the Coordination Committee shall agree on the portion of the total premium cost which is allocable to Operating Insurance. If the Participants are unable to agree on such allocation, the Operating Agent may make an estimated allocation and bill the Participants on the basis thereof, with adjustment to be made when the dispute is resolved.

31.9 If a Participant desires changes in any Operating Insurance policy, such Participant shall notify the Operating Agent and the other Participants in writing of the desired changes. Upon agreement of the Coordination Committee to such change, the Operating Agent shall obtain the insurance within sixty (60) days from the date of agreement. If the Operating Agent is unable to obtain the type of policy or coverage required herein or believed by the Operating Agent to be adequate, then the Operating Agent shall immediately notify the Participants.

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31.10 In the event the Coordination Committee is unable to agree upon any matters relating to the Operating Insurance, the Operating Agent, pending the resolution of such disagreement, shall procure or cause to be procured such policies of insurance, consistent with Prudent Utility Practice, as are necessary to protect the Participants against the insurable risks for which Operating Insurance is required. During any period of negotiations with an insurer, or other negotiations which are pending at the expiration of the period of coverage of an Operating Insurance policy, or in the event an Operating Insurance policy is canceled, the Operating Agent shall renew or bind policies as an emergency measure, or may procure policies of insurance which are identical to those which were canceled, or may to the extent possible secure replacement policies which will provide substantially the same coverage as the policy expiring or canceled.

31.11 Each Participant shall have the right to request that any mortgagee, trustee or secured party be named on all or any of the Operating Insurance policies as loss payees or additional assureds as their interests may appear. Such request shall be submitted to the Operating Agent specifying the name or names of such mortgagee, trustee or secured party and such additional information as may be necessary or required to permit it to be included on the policies of Operating Insurance.

31.12 On an annual basis, the Operating Agent shall advise the Participants on the status of insurance coverage for the San Juan Project and shall make appropriate recommendations concerning insurance issues to the Coordination Committee.

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32.0 SURPLUS OR RETIRED PROPERTY:

The Operating Agent shall dispose of surplus property of an operating Unit or property no longer used or useful in the operation of such a Unit and report such disposal to the Participants, both in accordance with practices and procedures established by the Engineering and Operating Committee. The proceeds from such disposition shall be credited to the Participants in accordance with their Participation Shares.

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33.0 REMOVAL OF OPERATING AGENT:

33.1 The Operating Agent shall serve as such during the term of this Agreement unless it resigns as Operating Agent by giving notice to the Participants at least one (1) year in advance of the date of resignation or until receipt by the Operating Agent of notice of its removal as provided in Section 33.2.

33.2 The Operating Agent may be removed as Operating Agent for any one of the following reasons:

33.2.1 The Operating Agent may be removed by action of the Coordination Committee if, in the judgment of the Coordination Committee (voting as provided for in Section 18.4), the best interests of the San Juan Project require that a new Operating Agent be selected. Any Participant seeking a Coordination Committee determination to remove the Operating Agent shall provide to the Operating Agent and to all of the Participants a written statement, detailing the reasons why, in the judgment of the initiating Participant, the Operating Agent should be removed. Within thirty (30) days after receipt by the Operating Agent of this written statement, the Operating Agent shall prepare and serve upon all of the Participants its response which shall contain a detailed rebuttal of the allegations made in the initiating statement. Within the same thirty (30) day period, any other Participant may also prepare and serve upon the Operating Agent and the Participants a statement responding to the allegations in the initiating statement. Within twenty (20) days after service of all such response statements, the Coordination Committee shall meet to consider what action, if any, to take with regard to the removal of the Operating Agent. If, pursuant to this Section 33.2.1, the Coordination Committee

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removes the Operating Agent, such removal shall be effective upon the date established by the Coordination Committee. If the Operating Agent or any Participant is dissatisfied with the action of the Coordination Committee, it shall have the right to seek arbitration under Section 37, but no demand for arbitration shall stay the decision of the Coordination Committee to remove the Operating Agent.

33.2.2 If, pursuant to the provisions of Section 34, it is determined that the Operating Agent is in default of its obligations under this Agreement, the Operating Agent may be removed by written notice given by any Participant under Section 34.1.2, which notice shall state the effective date of the removal of the Operating Agent.

33.2.3 Notwithstanding the pendency of any actions to remove the Operating Agent, the Operating Agent shall continue in good faith to exercise its obligations as Operating Agent.

33.3 Prior to the effective date of a resignation of the Operating Agent, or prior to the date of removal of the Operating Agent in accordance with Section 33.2, the Coordination Committee shall by written agreement designate a new Operating Agent, which may, but need not, be a Participant. The Coordination Committee may designate an interim Operating Agent pending selection of a permanent Operating Agent. Acceptance by the new Operating Agent of its appointment as such shall constitute its agreement to perform the obligations of the Operating Agent under this Agreement.

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34.0 DEFAULTS BY OPERATING AGENT:

34.1.1 In the event any Participant shall be of the opinion that an action taken or failed to be taken by the Operating Agent constitutes a violation of this Agreement, it may give written notice thereof to the Operating Agent and the other Participants, together with a statement of the basis for its opinion. Thereupon, the Operating Agent may prepare a statement of the reasons justifying its action or failure to take action. If agreement in settling the dispute is not reached between the Operating Agent and such Participant which gave such notice, then the matter shall be submitted to arbitration in the manner provided in Section 37. During the continuance of the arbitration proceedings, the Operating Agent may continue such action taken or failed to be taken in the manner it deems most advisable and consistent with this Agreement.

34.1.2 If it is determined that the Operating Agent is violating this Agreement, then the Operating Agent shall act with due diligence to end such violation and shall, within thirty (30) days or within such lesser time following the determination as may be prescribed in the determination, take action or commence action in good faith to terminate such violation. In the event that the complaining Participant is of the opinion that the Operating Agent has not taken such action to correct, or to commence action to correct, the violation within such allowed period, the complaining Participant shall be entitled to submit the question of the Operating

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Agent’s good faith action to terminate such violation to arbitration as provided in Section 37. If it is determined that the Operating Agent has not acted with due diligence or good faith to terminate such violation, it shall be deemed to be in default and shall be subject to removal, after the arbitration determination, within fifteen (15) days after receipt of notice executed by the complaining Participant in accordance with Section 42.

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PART VII

DEFAULTS, LIABILITY AND ARBITRATION

35. DEFAULTS:

35.1 Each Participant shall pay all monies and carry out all other performances, duties and obligations agreed to be paid or performed by it pursuant to all of the terms and conditions set forth and contained in the Project Agreements, and a default by any Participant in the covenants and obligations to be by it kept and performed pursuant to the terms and conditions set forth and contained in any of the Project Agreements shall be an act of default under this Agreement. A default under the Mine Reclamation Agreement or the Decommissioning Agreement is not a default under this Agreement. If a Participant breaches a performance obligation under Section 5 of the Restructuring Agreement, which provisions are incorporated in Section 23 of this Agreement, the non-defaulting Participants’ remedies shall be as provided in this Agreement. A default under any other section of the Restructuring Agreement shall not be a default under this Agreement, irrespective of whether it is incorporated in this Agreement, and remedies for such a default shall be as provided in the Restructuring Agreement.

35.2 In the event of a default by a Participant in any of the terms and conditions of this Agreement to be performed by that Participant, the following shall apply:

35.2.1 The Operating Agent shall give a written notice of the default to the defaulting Participant and the other Participants in accordance with Section 35.2.2.

35.2.2 The notice of default shall specify the existence, nature and extent of the default. Upon receipt of the notice of default, the defaulting Participant shall

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immediately take all steps necessary to cure the default as promptly and completely as possible.

35.3 In the event that any Participant shall dispute an asserted default by it, then such Participant shall pay the disputed payment or perform the disputed obligation, but may do so under protest. The protest shall be in writing, shall accompany the disputed payment or precede the performance of the disputed obligation(s), and shall specify the reason upon which the protest is based. Copies of such protest shall be mailed by such Participant to all other Participants and to the Operating Agent. Payments not made under protest shall be deemed correct, except to the extent that periodic or annual audits may reveal over or under payment by a Participant or may necessitate adjustments. In the event it is determined by arbitration, pursuant to the provisions of this Agreement or otherwise, that the protesting Participant is entitled to a refund of all or any portion of a disputed payment or payments, or is entitled to the reasonable equivalent in money of non-monetary performance of a disputed obligation theretofore made, then, upon such determination, the non-protesting Participant(s) shall reimburse such amount to the protesting Participant, together with interest thereon at the rate of ten percent (10%) per annum, or the maximum legal rate of interest, whichever is lesser, from the date of payment or of the performance of a disputed obligation to the date of reimbursement.

35.4 In the event a default shall continue for a period of ten (10) days or more after the notice given by the Operating Agent in accordance with Section 35.2 without having been cured by the defaulting Participant, or without such defaulting Participant having commenced or continued action in good faith to cure such default, the following shall apply:

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35.4.1 If the defaulting Participant has failed to cure such default or to commence such good faith action during said ten (10) day period, the Operating Agent shall make a written report to the Engineering and Operating Committee concerning the status of the default and shall, on the next working day after such ten (10) day period, notify the defaulting Participant in writing that the Operating Agent intends to declare the defaulting Participant in default under the Project Agreements unless there is a prompt cure of the default. Seven (7) days after the giving of such notice to the defaulting Participant, the Operating Agent shall make a second written report to the Engineering and Operating Committee concerning the status of the default and the efforts, if any, of the defaulting Participant to cure the default. If, within seven (7) additional days, the defaulting Participant has neither cured nor reasonably commenced to cure the default, the Operating Agent shall declare the defaulting Participant in default under the Project Agreements and shall provide written notification of the declaration of default to the defaulting Participant and to the Engineering and Operating Committee. Thereafter, and for so long as the default is not remedied and the declaration of default is not revoked by the Operating Agent, all rights of the defaulting Participant under the Project Agreements shall be suspended, including the right to vote on all committees and to receive all or any part of its proportionate share of the Net Effective Generating Capacity.

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apply during the period of suspension under Section 35.4.1. Upon approval by the Engineering and Operating Committee, the Operating Agent shall provide notice to each Participant of such special procedures. These special procedures shall include:

35.4.2.1 A tabulation in form similar to Section 6.2 of the percentages of costs to be borne by the non-defaulting Participants pursuant to Section 35.5;

35.4.2.2 Billing and accounting of such costs;

35.4.2.3 Dispatch and scheduling of the defaulting Participant’s proportionate share of Net Effective Generating Capacity; and

35.4.2.4 Any other items required for the optimal use of the San Juan Project and the mitigation of damages by the non-defaulting Participants.

35.4.2.5 If the Operating Agent proposes to broker all or a portion of the defaulting Participant’s proportionate share of Net Effective Generating Capacity on behalf of one or more non-defaulting Participants, the form of such an agreement shall be incorporated in such procedures.

35.4.3 Within twenty (20) days after the declaration of a default, as provided for in Section 35.4.1, the defaulting Participant and the non-defaulting Participants shall convene a meeting to address the defaulting Participant’s situation and its intentions with regard to curing its default. The defaulting Participant shall promptly prepare a cure plan for approval by the members of the Coordination Committee entitled to vote thereon. The cure plan shall address the defaulting Participant’s plan to cure the default and restore itself to full participation as an owner of the San Juan Project. The Coordination Committee, by vote of the

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members of the Coordination Committee entitled to vote thereon, will monitor the defaulting Participant’s compliance with the terms and conditions of the cure plan and if it appears to the Coordination Committee that the defaulting Participant is or will be unable to comply with the terms of an approved cure plan, the Coordination Committee shall consider what actions may be required to address such inability, including, but not limited to, directing the Operating Agent to take such actions as may be appropriate. It is the intent of the Participants that any defaults shall be cured on as expeditious a basis as reasonably possible.

35.4.4 A demand for arbitration of an asserted default pursuant to Section 37 shall not stay the suspension of the rights of the defaulting Participant, but in the event that the board of arbitrators shall determine that the asserted default did not in fact exist or occur, the arbitrators shall specify a method of fully and fairly compensating the Participant which, under Section 35.4.1, was denied the right to vote on committee actions and to receive all or any part of its proportionate share of the Net Effective Generating Capacity.

35.5 During any period when the suspension provided for in Section 35.4.1 is in effect, the non-defaulting Participant(s) having a Participation Share in the affected Unit or Units: (i) shall bear a proportionate share of all expenses, including but not limited to, the operation and maintenance costs, insurance costs, fuel costs, capital expenditures and other expenses otherwise payable by the defaulting Participant under the Project Agreements, including any obligations related to common equipment and facilities, based upon the relation of the Participation Share of each such non-defaulting Participant(s) to the Participation Shares of all non-defaulting Participants in the specific Unit or Units; and (ii)

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shall be entitled to schedule and receive for their accounts their proportionate share of the Net Effective Generating Capacity of the defaulting Participant.

35.6 In connection with its cure of the default, the defaulting Participant shall pay promptly upon demand to the non-defaulting Participant(s) the total amount of money (and/or the reasonable equivalent in money of non-monetary performance) paid and/or made by such non-defaulting Participant(s) pursuant to Section 35.5 in order to cure any default by the defaulting Participant, together with interest thereon at the rate of ten percent (10%) per annum, or the maximum legal rate of interest, whichever is the lesser, from the date of the expenditure of such money (or the making of such other performance) by the non-defaulting Participant(s), to the date of such reimbursement by the defaulting Participant, or such greater amount as may be otherwise provided in the Project Agreements. Any payment obligation of the defaulting Participant shall be reduced by mitigation measures undertaken by the non-defaulting Participants; provided, however, that the payment obligations of the defaulting Participant shall not be reduced by any profits or gains achieved by the non-defaulting Participants as the result of taking a proportionate share of the Net Effective Generating Capacity due to the default of the defaulting Participant.

35.7 The suspension of a defaulting Participant shall be terminated and its full rights under the Project Agreements restored when the default(s) have been cured and all compensable costs incurred by the non-defaulting Participant(s) hereunder have been paid by the defaulting Participant or other arrangements acceptable to the non-defaulting Participant(s) have been made.

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35.8 No waiver by a non-defaulting Participant of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall be effective unless the non-defaulting Participant(s) waive in writing their respective rights and any such waiver shall not be deemed to be a waiver with respect to any subsequent default or matter. No delay short of the statutory period of limitations in asserting or enforcing any right hereunder shall be deemed a waiver of such right.

35.9 The rights and remedies provided in this Agreement shall be in addition to the rights and remedies of the Participants as set forth and contained in any other Project Agreement or any rights and remedies the Participants have in law or equity.

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36.0 LIABILITY:

36.1 Except for any judgment debt for damage resulting from Willful Action and except to the extent any judgment debt is collectible from valid insurance, and subject to the provisions of Sections 36.1.1, 36.4, 36.5, 36.6 and Section 37, each Participant hereby extends to all other Participants, their directors, members of their governing bodies, officers and employees, its covenant not to execute, levy or otherwise enforce a judgment obtained against any of them, including recording or effecting a judgment lien, for any direct, indirect, or consequential loss, damage, claim, cost, charge or expense, whether or not resulting from the negligence of such Participant, its directors, members of its governing body, officers, employees or any person or entity whose negligence would be imputed to such Participant from (i) Operating Work, the design and construction of Capital Improvements or the use or ownership of the San Juan Project or (ii) the performance or nonperformance of the obligations of any Participant under any of the Project Agreements, other than the obligation to pay any monies becoming due.

36.1.1 In the event any insurer providing insurance refuses to pay any judgment obtained by a Participant against any other Participant, its directors, members of its governing body, officers or employees on account of liability referred to in Section 36.1, the Participant, its directors, members of its governing body, officers or employees against whom the judgment is obtained shall, at the request of the prevailing Participant and in consideration for the covenant granted in Section 36.1, execute such documents as may be necessary to effect an assignment of its contractual rights against the nonpaying insurer and thereby give the prevailing Participant the opportunity to enforce its judgment directly against such insurer. In

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no event when a judgment debt is collectible from valid insurance shall the Participant obtaining the judgment execute, levy or otherwise enforce the judgment (including recording or effecting a judgment lien) against the Participant, its directors, members of its governing body, officers or employees against whom the judgment was obtained.

36.1.2 To the extent that Section 41‑3‑5, New Mexico Statutes Annotated, 1978 compilation (as such section may be amended), shall be applicable and for the purpose of relieving each Participant, its directors, members of its governing body, officers and employees of any liability to make contribution to other non‑Participant tortfeasors, the foregoing covenant not to execute hereby effects a reduction of all injured Participants’ damages recoverable against all other non‑Participant tortfeasors to the extent of the pro rata share (as referred to in Section 41‑3‑5, New Mexico Statutes Annotated, 1978 compilation, as such section may be amended) of the other Participants, their directors, members of their governing bodies, officers and employees.

36.1.3 Each Participant agrees, upon request by any other Participant, to make, execute and deliver any and all documents or take such other action as may reasonably be required to effectuate the intent of this Section 36.1.

36.2 Except as provided in Sections 36.4, 36.5 and 36.6, the costs and expenses of discharging all work liability imposed upon one or more of the Participants, for which payment is not made by insurance, shall be allocated among the Participants in proportion to their respective Participation Shares in the property giving rise to the work liability. Work liability is defined as liability of one or more Participants for any loss, damage, claim, cost,

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charge or expense of any kind or nature (including direct, indirect or consequential) suffered or incurred by any party other than a Participant, whether or not resulting or to result in the future from the negligence of any Participant, its directors, members of its governing body, officers, employees or any other person or entity whose negligence would be imputed to such Participant, that has resulted or may result in the future from (i) performance or nonperformance of the work herein described, (ii) operation, maintenance, use or ownership of the San Juan Project, and (iii) past or future performance or nonperformance of the obligations of any Participant under any of the Project Agreements.

36.3 If it cannot be determined which property gave rise to work liability, the allocation for discharging costs and expenses associated therewith shall be as specified in Section 22.1.7.

36.4 Except for liability resulting from Willful Action (which subject to the provisions of Section 36.6 shall be the responsibility of the willfully acting Participant), any Participant whose electric customer shall have a claim or bring an action against any other Participant for any death, injury, loss or damage arising out of or in connection with electric service to such customer caused by the operation or failure of operation of the San Juan Project or any portion thereof shall indemnify and hold harmless such other Participant, its directors, members of its governing body, officers and employees from and against any liability for such death, injury, loss or damage.

36.5 Each Participant shall be responsible for any damage, loss, claim, cost, charge or expense that is not covered by insurance and results from its own Willful Action as defined in Section 5.57.2 and shall indemnify and hold harmless the other Participants,

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their directors, members of their governing bodies, officers and employees, from any such damage, loss, claim, cost, charge or expense.

36.6 Except as provided in Section 36.5, the aggregate liability of any Participant to all other Participants for Willful Action not covered by insurance shall be determined as follows:

36.6.1 All such liability for damages, losses, claims, costs, charges or expenses of such Participant shall not exceed fourteen million dollars ($14,000,000) per occurrence. Each Participant extends to each other Participant, its directors, members of its governing body, officers and employees its covenant not to execute, levy or otherwise enforce a judgment against any of them for any such aggregate liability in excess of fourteen million dollars ($14,000,000) per occurrence.

36.6.2 A claim based on Willful Action must be perfected by filing suit in a court of competent jurisdiction within three (3) years after the Willful Action occurs. All claims made thereafter relating to the same Willful Action shall be barred by this Section 36.6.2. The award to each nonwillfully acting Participant from each Participant determined to have committed Willful Action shall be determined as follows: (i) Each Participant who successfully files suit for remuneration shall receive the lesser of (a) its final judgment awarded (or settlement made) or (b) its pro rata Participation Share of the fourteen million dollar ($14,000,000) maximum recovery established in Section 36.6.1; (ii) When all pending suits are resolved, those Participants who were awarded judgments or reached settlements but whose claims were not fully satisfied pursuant to Section 36.6.2(i) shall be entitled to participate in any remaining portion of the fourteen

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million dollar ($14,000,000) maximum recovery limit, based upon the ratio of the unsatisfied portion of such Participant’s judgment or settlement to the total unsatisfied portion of all such judgments and settlements. Such participation shall be limited to the Participants’ unsatisfied judgments or settlements.

36.8 If a court of competent jurisdiction determines upon a challenge by a Participant or third party that the provisions of Section 56-7-1, New Mexico Statutes Annotated, 1978 Compilation, as amended, are applicable to this Agreement, the Participants agree that any agreement to indemnify contained in this Agreement shall be enforced only to the extent it requires the indemnitor to indemnify or hold harmless the indemnitee, including its officers, employees or agents, against liability, claims, damages, losses or expenses, including attorney’s fees, only to the extent that the liability, damages, losses or costs are caused by, or arise out of, the acts or omissions of the indemnitor or its officers, employees or agents.

36.9 The Participants agree that the aggregate liability limit of fourteen million dollars ($14,000,000) referenced in Sections 36.6.1 and 36.6.2 may be determined in the future to be inappropriate and shall, at the request of any Participant, make a good faith effort to evaluate and, if appropriate, revise said limit.

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37.0 ARBITRATION:

37.1 If a dispute between or among any of the Participants (which term, for purposes of this Section 37, shall be deemed to include the Operating Agent) should arise in relation to the performance or nonperformance of any obligation under this Agreement, any Participant(s) may call for submission of the dispute to arbitration, which call shall be binding upon all of the other affected Participant(s). Disputes arising under the Mine Reclamation Agreement and the Decommissioning Agreement shall be resolved pursuant to the dispute resolution provisions of those agreements. Disputes arising under Section 5 of the Restructuring Agreement, to the extent such provisions are incorporated in Section 23 of this Agreement, shall be resolved pursuant to the dispute resolution provisions of this Agreement. Any other disputes arising under the Restructuring Agreement shall be resolved pursuant to the dispute resolution provisions of the Restructuring Agreement.

37.2 The Participant(s) calling for arbitration shall give written notice to all other Participants, setting forth in such notice in adequate detail the entity(ies) against whom relief is sought, the nature of the dispute, the amount or amounts, if any, involved in such dispute, and the remedy sought by such arbitration proceedings. Within twenty (20) days after receipt of such notice, any other Participant(s) involved may, by written response to the first Participant(s), as well as the other Participant(s), submit its or their own statement of the matter at issue and set forth in adequate detail additional related matters or issues to be arbitrated. Thereafter, the Participant(s) first submitting its or their notice of the matter at issue shall have ten (10) days in which to submit a written rebuttal statement, copies of which shall be provided to all other Participants.

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37.3 Within ten (10) days following delivery of the last written submittal pursuant to Section 37.2, the affected Participant(s), acting through their respective representatives, shall meet for the purpose of selecting arbitrators. Each affected Participant, or group of Participants, representing one side of the dispute, shall designate an arbitrator. The arbitrators so selected shall meet within twenty (20) days following their selection and shall select additional arbitrator(s), the number of which additional arbitrators shall be one (1) less than the total number of arbitrators selected by the affected Participants. If the arbitrators selected by the affected Participants, as herein provided, shall fail to select such additional arbitrator(s) within said twenty (20) day period, then the arbitrators shall request from the American Arbitration Association (or similar organization if the American Arbitration Association should not exist at the time) a list of arbitrators who are qualified and eligible to serve as hereinafter provided. The arbitrators selected by the affected Participants shall take turns striking names from the list of arbitrators furnished by the American Arbitration Association, and the last name(s) remaining on said list shall be the additional arbitrator(s). All arbitrators shall be persons skilled and experienced in the field which gives rise to the dispute, and no person shall be eligible for appointment as an arbitrator who is an officer or employee of any of the Participants to the dispute or is otherwise interested in the matter to be arbitrated.

37.4 Except as otherwise provided in this Section 37 or otherwise agreed by the Participants to the dispute, the arbitration shall be governed by the rules and practices of the American Arbitration Association (or rules and practices of a similar organization if the American Arbitration Association should not exist at that time) from time to time in force, except that if such rules and practices, as modified herein, shall conflict with New Mexico

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Rules of Civil Procedure or any other provisions of New Mexico law then in force which are specifically applicable to arbitration proceedings, such New Mexico laws shall govern.

37.6 The arbitrators shall hear evidence submitted by the respective Participants or group or groups of Participants and may call for additional information, which additional information shall be furnished by the Participant having such information. The decision of a majority of the arbitrators shall be binding upon all the Participants and shall be based on the provisions of the Project Agreements and New Mexico law.

37.7 This agreement to arbitrate shall be specifically enforceable and the award of the arbitrators shall be final and binding upon the Participants to the extent provided by the laws of the State of New Mexico. Any award may be filed with the clerk of any court having jurisdiction over the Participants or any of them against whom the award is rendered, and, upon such filing, such award, to the extent permitted by the laws of the jurisdiction in which said award is filed, shall be specifically enforceable or shall form the basis of a declaratory judgment or other similar relief.

37.8 Each Participant or group of Participants shall be responsible for the fees and expenses of the arbitrator selected by that Participant or group of Participants, unless the decision of the arbitrators shall specify some other apportionment of such fees and expenses. The fees and expenses of the neutral arbitrators shall be shared among the affected Participants equally, unless the decision of the arbitrators shall specify some other

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apportionment of such fees and expenses. All other expenses and costs of the arbitration, including attorney fees, shall be borne by the Participant incurring the same.

37.9 In the event that any Participant(s) shall attempt to institute or to carry out the provisions herein set forth in regard to arbitration, and such Participant(s) shall not be able to obtain a valid and enforceable arbitration decree, such Participant(s) shall be entitled to seek legal remedies in a court having jurisdiction in the premises, and the provisions in this Section 37 referring to arbitration decisions shall then be deemed applicable to final decisions of such court.

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PART VIII

RETIREMENT AND RECONSTRUCTION

38.0 DESTRUCTION, DAMAGE OR CONDEMNATION OF A UNIT:

38.2 Failure to reach unanimous agreement as provided in Section 38.1 shall be deemed to be an election not to repair or reconstruct the damaged, destroyed or condemned Unit, in which event the proceeds from any insurance or from any award shall be distributed to the Participants in accordance with their respective Participation Shares in such Unit. Disposal of the facilities not destroyed, damaged or condemned shall be considered interim Decommissioning Work under Section 4.2 of the Decommissioning Agreement and the net proceeds from such disposal shall be distributed in accordance with the relevant provisions of the Decommissioning Agreement. Nothing in this section shall be deemed to preclude any Participant or group of Participants in the Unit from agreeing to repair, reconstruct or replace the damaged, destroyed or condemned Unit.

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39.0 RIGHTS OF PARTICIPANTS UPON TERMINATION:

39.1 In the event the Participants by unanimous agreement abandon, retire or otherwise terminate operation of the San Juan Project prior to the termination of this Agreement, the facilities forming the San Juan Project shall be disposed of or otherwise addressed in a manner consistent with the Decommissioning Agreement.

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40.0 DECOMMISSIONING OF THE PROJECT:

40.1 Upon the effective date of the Decommissioning Agreement, the decommissioning of the San Juan Project shall be governed by the Decommissioning Agreement.

40.2 If PNM or TEP determines, pursuant to Section 4.3.3 of the Decommissioning Agreement, to retain and not decommission certain of its solely owned facilities or property of the San Juan Project, such designating party will be responsible for decommissioning costs associated with such facilities or property. With respect to facilities or property of the San Juan Project jointly owned by PNM and TEP, any designation pursuant to Section 4.3.3 of the Decommissioning Agreement shall be made jointly by PNM and TEP, and both parties will be responsible for decommissioning costs associated with such facilities or property.

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40A.0 EXTENSION OF TERMINATION DATE FOR LARGE CAPITAL IMPROVEMENT:

40A.1 If the Coordination Committee votes on a CBI for a Large Capital Improvement as provided for in Section 18.4.4, and unanimously approves the Large Capital Improvement, then the project shall be performed and the Participants shall extend the term of this Agreement, if appropriate.

40A.2 If the Coordination Committee votes on a CBI for a Large Capital Improvement as provided for in Section 18.4.4, and does not unanimously approve the Large Capital Improvement, then the Participant(s) that voted against the Large Capital Improvement (each a “Disapprover”) shall have the right to negotiate with third parties or other Participants to market their share of the San Juan Project. PNM will have a right of first refusal to purchase any Disapprover’s interest in the San Juan Project as set forth in Section 11. If no third party or other Participant has agreed to purchase the Disapprover’s interest within three (3) months of the date of the CBI vote as evidenced by a binding agreement, then the Disapprover and the Participants that voted in favor of the Large Capital Improvement (each an “Approver”) shall negotiate in good faith for the conveyance of the Disapprover’s rights, titles and interests in the San Juan Project to other Participants, or other equitable option, in a manner consistent with this Agreement that assures the continued successful and proper operation and maintenance of the San Juan Project; provided, however, that no Approver is under any obligation to acquire the rights, titles and interests of the Disapprover. The Approver’s acquisition price for the Disapprover’s ownership interest shall be zero. No Participant shall unreasonably fail to

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grant any requisite approval to a sale or transfer by a Disapprover under this Section 40A.2.

40A.3 If the Participants cannot agree on a Disapprover’s sale or transfer of its respective rights titles and interests in the San Juan Project, or other equitable option, then the Disapprover shall retain its existing ownership interest in the San Juan Project and the Large Capital Improvement shall not be made.

40A.4 Any agreement pursuant to Section 40A.2 between a Disapprover and any Approver that acquires the Disapprover’s right, title and interest in the San Juan Project shall include the following provisions: (i) in the event TEP is a Disapprover, TEP shall transfer its water rights and San Juan Project land to PNM (but not ownership and rights in the Switchyard) when it transfers its other rights, titles and interests in the San Juan Project; (ii) the Disapprover shall continue to pay SJCC for coal pursuant to the then-current CSA through the date of transfer; (iii) the Disapprover shall continue to pay SJCC for CCR disposal pursuant to the then-current CCRDA through the date of transfer; (iv) the Disapprover shall not be responsible for any costs associated with any new or future extension of coal supply or CCRDA services; (v) the Approver shall purchase the coal inventory and fuel oil of the Disapprover at book value on the date of transfer; (vi) subject to the terms of the Mine Reclamation Agreement, the Participants shall negotiate in good faith to address the allocation of post-2017 reclamation liability between the Approvers and Disapprover; (vii) the Disapprover may elect its status as an Opt-in or Opt-out Participant to the extent provided in the Mine Reclamation Agreement; (viii) the responsibility of the Disapprover and the Approvers for Capital Improvements arising before the transfer shall be addressed; (ix) the Disapprover shall retain its transmission

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rights; (x) voting rights shall be adjusted to reflect the exit of the Disapprover and allow the Approvers to approve the Large Capital Improvement; (xi) an environmental baseline study shall be performed under terms agreed by the Approver and Disapprover and indemnification provided to the Disapprover for environmental liabilities arising after the date of transfer of the Disapprover’s rights, titles and interests in the San Juan Project, in a manner similar to the Restructuring Agreement; (xii) the Disapprover’s removal from this Agreement; and (xiii) subject to Section 43.9, after the date of transfer, Disapprovers are only responsible for costs and other obligations and liabilities arising under the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement.

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40B.0 EXTENSION OF TERMINATION DATE AND COAL SUPPLY AGREEMENT:

40B.1 No later than June 30, 2018, the Operating Agent shall have negotiated prices for coal for the San Juan Project, beginning July 1, 2022 for a time period and volume agreed upon by the Participants. Based upon pricing and other relevant information, the Participants shall provide notification in writing whether they wish to extend the CSA and the term of this Agreement beyond July 1, 2022 (each an “Extender”) or do not wish to do so (“Non-Extender”).

40B.2 If all Participants are Extenders, then the Participants shall negotiate a binding extension of the CSA and shall extend this Agreement for an appropriate term beyond July 1, 2022. If all Participants are Non-Extenders, then this Agreement shall terminate on July 1, 2022, and the Participants shall plan for an orderly closure of the San Juan Project in 2022.

40B.3 If one or more of the Participants are Non-Extenders, such Non-Extenders shall have the right to negotiate with third parties or Extenders to market their interest in the San Juan Project. The Non-Extender may sell its ownership interest in the Project to a third party or Extender and must have entered into a binding agreement by November 15, 2018. PNM shall have a right of first refusal to purchase any Non-Extenders’ interest in the San Juan Project as set forth in Section 11. If, by November 15, 2018, no third party or Extender has agreed to purchase the Non-Extenders’ interest in the San Juan Project, the Non-Extenders shall negotiate in good faith with the Extenders to convey the Non-Extenders’ rights, titles and interests in the San Juan Project to the Extenders in a manner that is consistent with this Agreement and assures the continued successful and proper operation and maintenance of the San Juan Project. The Extender’s acquisition

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price for the Non-Extenders’ ownership interests shall be zero. No Participant shall unreasonably fail to grant any requisite approval to a sale or transfer by a Non-Extender under this Section 40B.2. In the event the Extenders and Non-Extenders cannot reach agreement on the conveyance of such ownership interests, they shall plan for an orderly closure of the San Juan Project in 2022.

40B.4 Any agreement pursuant to Section 40B.3 between a Non-Extender and the Extender that acquires the Non-Extender’s right, title and interest in the San Juan Project shall include the following provisions: (i) in the event TEP is a Non-Extender, TEP shall transfer its water rights and San Juan Project land to PNM (but not ownership and rights in the Switchyard) when it transfers its other rights, titles and interests in the San Juan Project; (ii) the Non-Extenders shall continue to pay SJCC for coal pursuant to the then-current CSA through the date of the transfer; (iii) the Non-Extenders shall continue to pay SJCC for CCR disposal pursuant to the then-current CCRDA through the date of the transfer; (iv) the Non-Extenders shall not be responsible for any costs associated with post-2022 coal supply or CCRDA services; (v) the Extender shall purchase coal inventory and fuel oil of the Non-Extenders at book value on the date of transfer; (vi) subject to the terms of the Mine Reclamation Agreement, the Participants shall negotiate in good faith to address the allocation of post-2017 reclamation liability between Extenders and Non-Extenders; (vii) any Non-Extender may elect its status as an Opt-in or Opt-out Participant to the extent provided in the Mine Reclamation Agreement; (viii) the Non-Extenders will not be responsible for any Capital Improvements after November 15, 2018, that extend the life of the San Juan Project beyond June 30, 2022; (ix) the Non-Extenders will retain their transmission rights; (x) voting rights will be

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adjusted to reflect the exit of the Non-Extenders; (xi) an environmental baseline study shall be performed under terms agreed by the Extender and Non-Extender and indemnification provided to the Non-Extender for environmental liabilities arising after June 30, 2022, in a manner similar to the Restructuring Agreement; (xii) the Disapprover’s removal from this Agreement; and (xiii) subject to Section 43.9, after the date of transfer, Non-Extenders are only responsible for costs and other obligations and liabilities arising under the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement.

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PART IX

MISCELLANEOUS PROVISIONS

41.0 RELATIONSHIP OF PARTICIPANTS:

41.1 The covenants, obligations and liabilities of the Participants are intended to be several and not joint or collective, and nothing herein contained shall ever be construed to create an association, joint venture, trust or partnership, or to impose a trust or partnership covenant, obligation or liability on or with regard to any one or more of the Participants. Each Participant shall be individually responsible for its own covenants, obligations and liabilities as herein provided. No Participant or group of Participants shall be under the control of or shall be deemed to control any other Participant or the Participants as a group. No Participant shall be the agent of or have a right or power to bind any other Participant without its express written consent, except as expressly provided herein.

41.2 The Participants hereby elect to be excluded from the application of Subchapter “K” of Chapter 1 of Subtitle “A” of the Internal Revenue Code of 1986, or such portion or portions thereof as may be permitted or authorized by the Secretary of the Treasury or its delegate insofar as such subchapter, or any portion or portions thereof, may be applicable to the Participants hereunder.

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42.0 NOTICES:

42.1.1 Public Service Company of New Mexico

Attn: Vice President, PNM Generation

2401 Aztec NE, Bldg. A

Albuquerque, NM 87107

With a copy to:

Public Service Company of New Mexico

c/o Secretary

414 Silver Ave. SW

Albuquerque, New Mexico 87102

42.1.2 Tucson Electric Power Company

88 E. Broadway Blvd.

MS HQE901

Tucson, Arizona 85701

Attn: Corporate Secretary

42.1.3 City of Farmington

c/o City Clerk

800 Municipal Drive

Farmington, NM 87401

With a copy to:

Farmington Electric Utility System

Electric Utility Director

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101 North Browning Parkway

Farmington, NM 87401

42.1.4 [Omitted]

42.1.5 [Omitted]

42.1.6 [Omitted]

42.1.7 Incorporated County of

Los Alamos, New Mexico

c/o County Clerk

1000 Central Ave.

Suite 240

Los Alamos, NM 87544

with a copy to:

Incorporated County of

Los Alamos, New Mexico

c/o Utilities Manager

1000 Central Ave.

Suite 130

Los Alamos, NM 87544

42.1.8 Utah Associated Municipal Power Systems

c/o General Manager

155 North 400 West

Suite 480

Salt Lake City, UT 84103

42.1.9 [Omitted]

42.1.10 PNMR Development and Management Corporation

c/o Corporate Secretary

PNM Resources, Inc.

Corporate Headquarters

414 Silver Avenue SW

Albuquerque, NM 87158-1245

42.2 A Participant may, at any time or from time to time, by written notice to the other Participants, change the designation or address of the person so specified as the one to receive notices pursuant to this Agreement.

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42.3 The Operating Agent shall provide to each Participant a copy of any material notice, demand or request given or received by it in connection with the San Juan Project.

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43.0 OTHER PROVISIONS:

43.1 Each Participant agrees, upon request by another Participant, to make, execute and deliver any and all documents reasonably required to implement the terms of this Agreement.

43.2 No Participant shall be considered to be in default in the performance of any of the obligations hereunder (other than obligations of a Participant to pay costs and expenses) if failure of performance shall be due to uncontrollable forces. The term “uncontrollable forces” shall mean any cause beyond the control of the Participant affected, including but not limited to failure of facilities, flood, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance, labor dispute, sabotage or terrorism, restraint by court order or public authority, or failure to obtain approval from a necessary governmental authority which by exercise of due diligence and foresight such Participant could not reasonably have been expected to avoid and which by exercise of due diligence it shall be unable to overcome. Nothing contained herein shall be construed so as to require a Participant to settle any strike or labor dispute in which it may be involved. Any Participant rendered unable to fulfill any obligation by reason of uncontrollable forces shall exercise due diligence to remove such inability with all reasonable dispatch.

43.3 The captions and headings appearing in this Agreement are inserted merely to facilitate reference and shall have no bearing upon the interpretation of the provisions hereof.

43.4 This Agreement is made under and shall be governed by the laws of the State of New Mexico, without regard to conflicts of law principles.

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43.5 The covenants and obligations set forth and contained in this Agreement are to be deemed to be independent covenants, not dependent covenants, and the obligation of a Participant to perform all of the obligations and covenants to be by it kept and performed is not conditioned on the performance by another Participant of all of the covenants and obligations to be kept and performed by it.

43.7 All costs or expenses, including all taxes that the Operating Agent is required to pay (but not specifically referred to in other sections of this Agreement), which are incurred by the Operating Agent in connection with the performance of its obligations under this Agreement and which are not specifically allocated to the Participants in accordance with this Agreement shall be equitably allocated among the Participants in a manner to be established by the Coordination Committee.

43.8 Should a change in circumstances, economic factors, or basic technology occur which results or may result in a substantial increase or decrease in the benefits to or expenses incurred by a Participant, including the Operating Agent, which such change was not within the reasonable contemplation of the Participants at the time of the execution of this Agreement, the Participants, including the Operating Agent, shall negotiate in good faith in order that an appropriate and equitable adjustment shall be made in the reimbursement of the Operating Agent and in the allocation of expenses among the

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Participants. Such adjustment shall be fair and equitable as to both the Operating Agent and the other Participants.

43.9 The execution of this Agreement shall not affect any rights or obligations of the Participants which shall have accrued prior to the effective date of this Agreement, including any such obligation to pay money or take other actions in accordance with the Original San Juan PPA, the Amended and Restated San Juan PPA, the Restructuring Amendment Amending and Restating the Amended and Restated San Juan PPA, the UG-CSA, the Co-Tenancy Agreement, the Operating Agreement, the Restructuring Agreement, the Decommissioning Agreement, the Mine Reclamation Agreement or any other San Juan Project-related agreement.

43.10 Except as provided in Sections 35.1 and 37.1, to the extent of any conflict between this Agreement and the Restructuring Agreement, the provisions of the Restructuring Agreement shall control.

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44.0 EXECUTION IN COUNTERPARTS:

44.1 This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument as if all the Participants to the aggregated counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart thereof without impairing the legal effect of any signatures thereon and may be attached to any other counterpart of this Agreement identical in form thereto but having attached to it one or more additional pages. Electronic or pdf signatures have the same effect as an original signature.

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45.0 AMENDMENTS:

45.1 Except as provided in Section 45.2, this Agreement may be amended only by written instrument executed by all of the Participants with the same formality as this Agreement.

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IN WITNESS WHEREOF , the undersigned parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

Remaining Participants

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By____ /s/ Chris M. Olson_ _______________

Its__ Vice President, Generation _________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

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IN WITNESS WHEREOF , the undersigned parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

Remaining Participants

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By: _ /s/_Mark Mansfield ________________

Its: ___ VP Energy Resources__________

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

155 Exit Date Amendment 7/31/2015

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IN WITNESS WHEREOF , the undersigned parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

Remaining Participants

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By: _ /s/ _ Robert Mayes________________

Its: __ City Manager __________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

155 Exit Date Amendment 7/31/2015

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IN WITNESS WHEREOF , the undersigned parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

Remaining Participants

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By: _ /s/ Kristin Henderson ____________

Its: _ Council Chair _________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By______________________________________

Its____________________________________

155 Exit Date Amendment 7/31/2015

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IN WITNESS WHEREOF , the undersigned parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31 ^st day of July, 2015.

Remaining Participants

PUBLIC SERVICE COMPANY

OF NEW MEXICO

By___________________________________

Its_________________________________

TUCSON ELECTRIC POWER COMPANY

By___________________________________

Its_________________________________

THE CITY OF FARMINGTON, NEW MEXICO

By______________________________________

Its____________________________________

THE INCORPORATED COUNTY OF LOS ALAMOS,

NEW MEXICO

By______________________________________

Its____________________________________

UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS

By: __/s/ Douglas Hunter_______________

Its: ___ General Manager______________

155 Exit Date Amendment 7/31/2015

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PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By: _ /s/ Elisabeth Eden_____ ____________

Its: _ President, Chief Executive Officer and Treasurer

Exiting Participants

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

Exit Date Amendment 7/31/2015

EXECUTION VERSION

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

Exiting Participants

M-S-R PUBLIC POWER AGENCY

By: _ /s/_Martin Hopper _____________

Its: __ General Manager ____________

SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By______________________________________

Its____________________________________

156 Exit Date Amendment 7/31/2015

EXECUTION VERSION

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

Exiting Participants

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By: _/s/ Fred Mason__________________

Its: __President____________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By______________________________________

Its____________________________________

156 Exit Date Amendment 7/31/2015

EXECUTION VERSION

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

Exiting Participants

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

APPROVED AS TO FORM:

MICHAEL R.W. HOUSTON, CITY ATTORNEY

By: __/s/_Dukku Lee_______________ BY ________ _/s/ Alison M. Kott 7-27-15___

Dukku Lee Alison M. Kott, Assistant City Attorney

Public Utilities General Manager

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By______________________________________

Its____________________________________

156 Exit Date Amendment 7/31/2015

EXECUTION VERSION

PNMR DEVELOPMENT AND MANAGEMENT CORPORATION

By ________________________________________

Its_______________________________________

Exiting Participants

M-S-R PUBLIC POWER AGENCY

By______________________________________

Its____________________________________

SOUTHERN CALIFORNIA PUBLIC POWER

AUTHORITY

By______________________________________

Its____________________________________

CITY OF ANAHEIM

By______________________________________

Its____________________________________

TRI-STATE GENERATION AND TRANSMISSION

ASSOCIATION, INC.

By: __/s/_Micheal McInnes_ ____________

Its: _ __ CEO_ ______

156 Exit Date Amendment 7/31/2015

EXECUTION VERSION

STATE OF NEW MEXICO )

)ss.

COUNTY OF BERNALILLO )

The foregoing instrument was acknowledged before me on this _ 30 ^th day of June , 2015, by _ Chris M. Olson ___, _____ VP, Generation ________________ of Public Service Company of New Mexico, a New Mexico corporation, on behalf of the corporation.

/s/ Patricia A. Salls

Notary Public

My commission expires:

September 14, 2018

STATE OF ARIZONA )

)ss.

COUNTY OF PIMA )

The foregoing instrument was acknowledged before me on this ____ day of _____, 2015, by ________________________, _____________________ of Tucson Electric Power Company, an Arizona corporation, on behalf of the corporation.

Notary Public

My commission expires:

Exit Date Amendment 7/31/2015

EXECUTION VERSION

STATE OF NEW MEXICO )

)ss.

COUNTY OF BERNALILLO )

The foregoing instrument was acknowledged before me on this ____ day of _____, 2015, by ________________________, _____________________ of Public Service Company of New Mexico, a New Mexico corporation, on behalf of the corporation.

Notary Public

My commission expires:

STATE OF ARIZONA )

)ss.

COUNTY OF PIMA )

The foregoing instrument was acknowledged before me on this _ 1 ___ day of July , 2015, by _ Mark ____________, _ Mansfield __________________ of Tucson Electric Power Company, an Arizona corporation, on behalf of the corporation.

/s/ Cheryl T. Gottshall

Notary Public

My commission expires:

June 30, 2018

157 Exit Date Amendment 7/31/2015

EXECUTION VERSION

STATE OF NEW MEXICO )

)ss.

COUNTY OF SAN JUAN )

The foregoing instrument was acknowledged before me on this _ 1st __ day of July , 2015, by _ Robert Mayes _______________, _ City Manager __________ of The City of Farmington, New Mexico, a New Mexico municipal corporation, on behalf of the municipal corporation.

/s/ Melody A. Coyner

Notary Public

My commission expires:

5/29/19

STATE OF CALIFORNIA )

)ss.

COUNTY OF _____________ )

The foregoing instrument was acknowledged before me on this ____ day of July, 2015, by ________________________, _____________________ of M-S-R Public Power Agency, a California joint powers agency, on behalf of said joint powers agency.

Notary Public

My commission expires:

158 Exit Date Amendment 7/31/2015

EXECUTION VERSION

STATE OF NEW MEXICO )

)ss.

COUNTY OF LOS ALAMOS )

/s/ Melissa A. Salmon

Notary Public

My commission expires:

__01-07-2018_____

STATE OF CALIFORNIA )

)ss.

COUNTY OF ________________ )

The foregoing instrument was acknowledged before me on this ____ day of July, 2015, by ________________________, _____________________ of Southern California Public Power Authority, a California joint powers agency, on behalf of said joint powers agency.

Notary Public

My commission expires:

159 Exit Date Amendment 7/31/2015

EXECUTION VERSION

STATE OF CALIFORNIA )

)ss.

COUNTY OF ORANGE )

The foregoing instrument was acknowledged before me on this ____ day of July, 2015, by ________________________, _____________________ of the City of Anaheim, a California municipal corporation, on behalf of the said municipal corporation.

Notary Public

My commission expires:

STATE OF UTAH )

)ss.

COUNTY OF SALT LAKE )

The foregoing instrument was acknowledged before me on this _ 30th _ day of July, 2015, by _ Douglas Hunter _________, __ General Manager _________ of Utah Associated Municipal Power Systems, a political subdivision of the State of Utah, on behalf of said entity.

/s/ Andrea Miller

Notary Public

My commission expires:

June 15, 2019

160 Exit Date Amendment 7/31/2015

EXECUTION VERSION

STATE OF COLORADO )

)ss.

COUNTY OF ADAMS )

The foregoing instrument was acknowledged before me on this ____ day of July, 2015, by ________________________, _____________________ of Tri-State Generation and Transmission Association, Inc., a Colorado cooperative corporation, on behalf of the said cooperative corporation.

Notary Public

My commission expires:

STATE OF NEW MEXICO )

)ss.

COUNTY OF BERNALILLO )

The foregoing instrument was acknowledged before me on this _30 ^th day of June , 2015, by ___ Elisabeth Eden ____, ____ President, CEO and Treasurer __ of PNMR Development and Management Corporation, a New Mexico corporation, on behalf of the corporation.

/s/ G. Marcella Kercher

Notary Public

My commission expires:

12/19/2015

Exit Date Amendment 7/31/2015

CALIFORNIA ALL-PURPOSE ACKNOWLEDGMENT CIVIL CODE § 1189

State of California )

County of ____ Amador ___________________)

On __ July 27, 2015 _________before me, _________ Lynn V. Verhagen, Notary Public ______________ , Date Here Insert Name and Title of the Officer

personally appeared _______ Martin R. Hopper ______________________________________________

Name(s) of Signer(s)

____________________________________________________________________________________

who proved to me on the basis of satisfactory evidence to be the person( s ) whose name( s ) is/are

subscribed to the within instrument and acknowledged to me that he /she/they executed the same in

his /her/their authorized capacity( ies ), and that by his/ her/their signature( s ) on the instrument the person( s ),

or the entity upon behalf of which the person( s ) acted, executed the instrument.

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

Signature_ /s/ Lynn V. Verhagen _________

Signature of Notary Public

Place Notary Seal Above

-----------------------------------------------------------------OPTIONAL----------------------------------------------------------

Though this section is optional, completing this information can deter alteration of the document or

fraudulent reattachment of this form to an unintended document.

Description of Attached Document

Title or Type of Document:___ Exit Date Amendment _________ Document Date: ___ 7/27/15 ______

Number of Pages: ___ 161 ____ Signer(s) Other Than Named Above:

______________________________Capacity(ies) Claimed by Signer(s)



□Signer's Name:_____________________	□Signer's Name:_____________________
□Corporate Officer ___ Title(s):_________	□Corporate Officer ___ Title(s):_________
□Partner - □Limited □General	□Partner - □Limited □General
□Individual □Attorney in Fact	□Individual □Attorney in Fact
□Trustee □Guardian or Conservator	□Trustee □Guardian or Conservator
□Other: ____________________________	□Other: ____________________________
Signer Is Representing: _______________	Signer Is Representing: _______________
__________________________________	__________________________________

CALIFORNIA ALL-PURPOSE ACKNOWLEDGMENT

CIVIL CODE § 1189

State of California )

County of ____ Los Angeles ___________________)

On __ July 16, 2015 _________before me, _________ Salpi Ortiz, a notary public ________________ , Date Here Insert Name and Title of the Officer

personally appeared _______ Fred Mason ___________________________________

Name(s) of Signer(s)

____________________________________________________________________________________

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

Signature_ /s/ Salpi Ortiz _________

Signature of Notary Public

Place Notary Seal Above

-----------------------------------------------------------------OPTIONAL----------------------------------------------------------

Though this section is optional, completing this information can deter alteration of the document or fraudulent reattachment of this form to an unintended document.

Description of Attached Document

Title or Type of Document:_________________________ Document Date: ___ ______ ______

Number of Pages: _______ Signer(s) Other Than Named Above: ______________________________

Capacity(ies) Claimed by Signer(s)



□Signer's Name:_____________________	□Signer's Name:_____________________
□Corporate Officer ___ Title(s):_________	□Corporate Officer ___ Title(s):_________
□Partner - □Limited □General	□Partner - □Limited □General
□Individual □Attorney in Fact	□Individual □Attorney in Fact
□Trustee □Guardian or Conservator	□Trustee □Guardian or Conservator
□Other: ____________________________	□Other: ____________________________
Signer Is Representing: _______________	Signer Is Representing: _______________
__________________________________	__________________________________

CALIFORNIA ALL-PURPOSE ACKNOWLEGEMENT CIVIL CODE #1189

STATE OF CALIFORNIA )

)ss.

COUNTY OF ORANGE )

On July 27, 2015 before me, Annie DeSouza , Notary Public, personally

I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.

WITNESS my hand and official seal.

___/s/ Annie DeSouza___

[SEAL]

EXECUTION VERSION

STATE OF COLORADO )

)ss.

COUNTY OF ADAMS )

The foregoing instrument was acknowledged before me on this _ 22 _ day of July, 2015, by __ _Micheal S. McInnes _____, _ CEO___ _________________ of Tri-State Generation and Transmission Association, Inc., a Colorado cooperative corporation, on behalf of the said cooperative corporation.

/s/ Penny L. McLaughlin

Notary Public

My commission expires:

9/11/2018

161 Exit Date Amendment 7/31/2015

REFERENCES TO EXHIBITS IN

PARTICIPATION AGREEMENT

Exhibit No . References in Agreement Subject Matter

I §§ 2.10, 6.1 Real Property

II [Omitted]

III §§ 5.44, 6.5 Switchyard Facilities

IV §§ 6.2, 6.2.8 Ownership of Equipment

V §§ 22.1.7, 22.1.9 O&M of Equipment

VI §§ 7.11, 22.2.2, 22.6, 22.6.1, 22.7-8 A&G Expense

VII [Omitted]

VIII §§ 18.4, 19.4, 20.5, 21.4 Adjustment of Voting

EXHIBIT I

This Exhibit I to the Exit Date Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement contains a map of the San Juan Project Generating Station site and the River Weir site, showing Parcels A, B, C, C-1 D, E and F, the parcels of real property underlying the San Juan Project and River Weir sites. Also included in the Exhibit are property descriptions and separate maps showing Parcels A through F. PNM and TEP each has a one-half undivided ownership interest in the parcels described as Parcels A, B, C, D, E and F; and PNM and TEP each has a one-half leasehold interest in Parcel C-1.

Exh. I - 1

PARCEL A

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 16: SW 1/4

Section 20: NE 1/4, N 1/2 SE 1/4, SW 1/4SE 1/4

Section 21: NW 1/4 NW 1/4

Section 29: NE 1/4

PARCEL B

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SW 1/4, SW 1/4 SE 1/4

Section 20: E 1/2 NW 1/4, NE 1/4 SW 1/4

Section 29: NW 1/4, N 1/2 SW 1/4

Section 30: NE 1/4, E 1/2 NW 1/4, N 1/2 SE 1/4

PARCEL C

That part of Lot 6 in Section 4 and of Lot 5 in Section 3, Township 29 North, Range 15 West, N.M.P.M., San Juan County, New Mexico, described as follows:

Beginning at a point which is 772.69 feet, South 88º12’03” East from Northwest Corner of Lot 6:

PARCEL C-1

Exh. I - 2

PARCEL D

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 17: SE 1/4 SW 1/4, S1/2 SE 1/4

PARCEL E

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 19: SE 1/4 SE 1/4

NE 1/4 SE 1/4

E 1/2 NW 1/4 SE 1/4

S 1/2 S 1/2 SE 1/4 NE 1/4

Section 20: SE 1/4 SW 1/4

SW 1/4 SW 1/4

NW 1/4 SW 1/4

S 1/2 SW 1/4 SW 1/4 NW 1/4

Containing 235 acres, more or less.

PARCEL F

The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:

Section 20: SE 1/4 SE 1/4

Exh. I - 3

Exh. I - 4

Exh. I - 5

Exh. I - 6

Exh. I - 7

Exh. I - 8

Exh. I - 9

Exh. I - 10

EXHIBIT II

[Omitted]

Exh. II - 1

EXHIBIT III

SAN JUAN PROJECT SWITCHYARD FACILITIES

Material List



Phase I – Project (DWG, ED-54, ED-55)
QUANTITY	DESCRIPTION
5	345 kV Circuit Breakers – (G.E. A.T.B.’s)
16	345 kV Motor Operated Disconnect Switches with Stands

2	345 kV S&C Circuit Switches with Stands
Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
4	Line Deadend Towers
5	Intermediate Bus Towers
1	Start-Up Transformers 345/12.47/4.16 kV, 24/32/40 MVA
1	Set of 4.16 kV Switchgear
1	4.16 kV Start-Up Cable Run into Plant
2	4.16 kV Station Service Transformers
1	Set of 12.45 kV Switchgear
3	12.47 kV Zig-Zag Grounding Transformer
6	345 kV PCM Potential Transformers with Stands (Bus #1, Bus #2)
6	345 kV Bus Lightning Arresters with Stands

1	Control House 40’ x 72’
2	Sets of Batteries & Chargers, 125 v and 48 v
1	Microwave Tower
Lot	Cable Troughs, Equipment Controls, Breaker Failure Relaying, Fault Recorder
Lot	Metering – Indication, Billing and Telemetry Transducers
Lot	Switchyard Foundations, Fencing, Grading, Grounding

1	Line Trap (FC Line)
1	345 kV PCM Potential Transformer/Coupling Capacitor with Stand
3	345 kV Line Lightning Arresters with Stands
Lot	Line Relaying, Carrier, Microwave
1	345-69-12470 Transformer
1	345/230-12470 Transformer, 230 yard
1	Reactor – 12.47 kV, 345 yard

Exh. III - 1



Phase 2 – Project (DWG. SK-135)
QUANTITY	DESCRIPTION
4	345 kV Circuit Breakers
3	345 kV Motor Operated Disconnect Switches with Stands

Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
1	Intermediate Bus Tower
Lot	Cable Troughs, Equipment Controls, Breaker Failure Relaying
Lot	Metering – Indication, Billing and Telemetry Transducers
Lot	Switchyard Foundations, Grounding

Phase 3 – Project (DWG. SK-316)
3	345 kV Circuit Breakers
6	345 kV Motor Operated Disconnect Switches with Stands
Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
1	Line Deadend Tower
2	Intermediate Bus Towers
Lot	Cable Troughs, Equipment Controls, Breaker Failure Relaying
Lot	Metering – Indication, Billing and Telemetry Transducers
Lot	Switchyard Foundations and Grounding

Phase 3 – Project (DWG. SK-317)
2	345 kV Circuit Breakers
4	345 kV Motor Operated Disconnect Switches with Stands
Lot	Strain Bus and Fittings
Lot	Rigid Bus and Fittings
1	Intermediate Bus Tower
Lot	Switchyard Foundations, Grounding

Exh. III - 2

EXHIBIT IV

EXHIBIT IV(a)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 1

Ownership



PNM -	50	%	TEP -	50	%
PNMR-D	0	%	Farmington -	0	%
UAMPS -	0	%	LAC-	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment.)


12.	Fly Ash System

Exh. IV - 1

EXHIBIT IV(a)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	SSR Protection System


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. IV - 2

EXHIBIT IV(b)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 2

Ownership



PNM -	50	%	TEP -	50	%
PNMR-D -	0	%	Farmington -	0	%
UAMPS -	0	%	LAC -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment.)


12.	Fly Ash System

Exh. IV - 3

EXHIBIT IV(b)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. IV - 4

EXHIBIT IV(c)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 3

Ownership



PNM -	100	%	TEP -	0	%
PNMR-D	0	%	Farmington -	0	%
UAMPS -	0	%	LAC -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 3A and 3B Transformers*


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, Storage Tank, and Pump House


12.	Fly Ash System

Exh. IV - 5

EXHIBIT IV(c)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	Coal Reclaim Hoppers, Feeders, Feeder Belts, Belt Scales, Fire Protection System, and 3C Conveyor to the Secondary Crusher Building


20.	SSR Protection System


21.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant


*	PNM and TEP each owns a 50% interest in the main unit transformer

Exh. IV - 6

EXHIBIT IV(d)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNIT NO. 4

Ownership



PNM -	64.482	%	TEP -	0	%
PNMR-D	12.815	%	Farmington -	8.475	%
UAMPS -	7.028	%	LAC -	7.2	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 4A and 4B Transformers


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, Storage Tank, and Pump House


12.	Fly Ash System

Exh. IV - 7

EXHIBIT IV(d)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	Coal Reclaim Hoppers, Feeders, Feeder Belts, Belt Scales, Fire Protection System, and 3D Conveyor to the Secondary Crusher Building


20.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant

Exh. IV - 8

EXHIBIT IV(e)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNITS NO. 1 AND 2

Ownership



PNM -	50	%	TEP -	50	%
PNMR-D	0	%	Farmington -	0	%
UAMPS -	0	%	LAC -	0	%


1.	Bearing Cooling Water System


2.	Bottom Ash Dewatering Facility including: Dewatering Tank, Settling Tank, Surge Tank, Storage Tank, and Pump House


3.	Demineralizer System including: Clarifier, Storage Tanks, and Sump Pump


4.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization)


5.	Premix Tank Facility (This was the wastewater neutralizer facility and is now operated as part of the Water Management System.)


6.	Instrument Air system, except Unit Piping


7.	Chemical Feed System, except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System


8.	Plant Air System, except Unit Piping


9.	Sootblowing Air System, except Unit Piping


10.	Hydrogen Storage System, except Unit Piping

Exh. IV - 9

EXHIBIT IV(e)

(continued)


11.	Coal Handling Reclaim Systems A and B including: Hoppers, Feeders, Reclaim Conveyors, Belt Scales, and Sprinkler System


12.	Coal Tripper System south of column, Line 12 including Dust Collection System


13.	Turbine Lube Oil Storage and Transfer System


14.	Control Room, Equipment Rooms, and Associated HVAC System


15.	Turbine Crane south of column, Line 12


16.	Fuel Oil, Ash, and Water Pipe Racks


17.	Boiler Fill System for Units 1 and 2


18.	All spare parts common to either unit


19.	SO2 Backup Scrubber-Absorber Transformer


20.	SAR Multiplexer Control System

Exh. IV - 10

EXHIBIT IV(f)

FACILITIES AND EQUIPMENT SPECIFIC

TO SAN JUAN UNITS NO. 3 AND 4

Ownership



PNM -	64.482	%	TEP -	0	%
PNMR-D	12.815	%	Farmington -	8.475	%
UAMPS -	7.028	%	LAC -	7.2	%

1. Bearing Cooling Water System

2. Demineralizer System: including Sump Pumps, Filter Beds, and Storage Tanks


3.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization except Ignitor Heaters and Unit Specific Piping)


4.	Wastewater Neutralizer Facility (This facility is operated as part of Water Management System.)

5. Instrument Air System except Unit Piping

6. Chemical Feed System except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System

7. Plant Air System except Unit Piping

8. Sootblowing Air System except Unit Piping

9. Start-Up Transformers and Nonseg Bus to Units 3 and 4 Switchgear

10. Hydrogen Storage System except Unit Piping

11. Coal Tripper System Serving Units 3 and 4 including Dust Collection Systems

Exh. IV - 11

EXHIBIT IV(f)

(continued)

12. Turbine Lube Oil Storage and Transfer System

13. Control Room, Equipment Rooms, and Associated HVAC System

14. Boiler Fill System for Units 3 and 4


15.	Auxiliary Cooling Systems including Auxiliary Cooling Tower No. 1 and Pumps, but excepting No. 4 Tower Pumps and Piping which is Unit Specific

16. CO2 Storage System

17. Start-Up Boiler Feed Pump

18. Turbine Bay Crane north of column, Line 12

19. Fuel Oil, Ash, and Water Pipe Racks

20. Fire Water Booster and Jockey Pumps

21. Halon Fire Protection System

22. Cooling Tower Multiplex Control System

23. All spare parts common to either unit

Exh. IV - 12

EXHIBIT IV(g)

FACILITIES AND EQUIPMENT

COMMON TO ALL FOUR SAN JUAN UNITS

Ownership



PNM -	58.671	%	TEP -	20.068	%
PNMR-D	7.673	%	Farmington -	5.076	%
UAMPS -	4.203	%	LAC -	4.309	%


1.	River and Raw Water System including:


a.	Diversion and intake structures, including all equipment and pump building.


b.	Raw Water line to reservoir.


c.	Reservoir, pump buildings, and all equipment.


d.	Raw water lines to plant yard.


e.	All above and underground fire protection system to each vendor supplied or unit specific fire protection system.

2. Auxiliary Boiler

3. SO2 Removal System except Absorbers

3.1 SO2 Absorber Feed System


a.	Limestone Handling System


b.	Limestone Preparation System


c.	Dewatering System


d.	Gypsum Stack Out System

Exh. IV - 13

EXHIBIT IV(g)

(continued)

3.2 SO2 Chemical Plant


a.	Double effect evaporator train systems.


b.	Fly ash filter system.


c.	Absorber product and feed tanks.


d.	Condensate collection, storage, and transfer systems.


e.	Soda ash storage, mixing, and distribution systems.


f.	Sulfate purge system including: crystallizers, centrifuges, evaporators, and salt cake system.


g.	Sulfuric acid plant system including storage tanks and load out system.


h.	Auxiliary. No. 2 cooling tower, pumps, and systems.

4. Spare-Main Transformer 345/24 kV for all units.

5. Maintenance, Office, and Warehousing Facilities

6. Chemical Laboratory

7. Coal and Ash Handling Control Facilities

8. Roads and grounds such as fencing, yard lighting, guard facilities, drainage, and dikes.

9. Potable Water System


10.	Environmental Monitoring systems including Air, Water, and Ground. Excludes Stack Monitoring Systems which are unit specific.

11. Transportation such as trucks, cars, and dozers (not otherwise charged).

12. Water Management System


a.	Wastewater Recovery System -- Northside


1.	Reverse osmosis system including lime/soda softening clarifier system.


2.	Brine concentrator Nos. 4 and 5.


3.	Process pond No. 3 and pump system


4.	North evaporation ponds 1, 2, and 3.

Exh. IV - 14

EXHIBIT IV(g)

(continued)


b.	SO2 Waste Treatment System -- Southside


1.	Process ponds 1A, 1 B, 2 and pumping system.


2.	Premix tank and clarifier system.


3.	Oxidation towers.


4.	Brine concentrator Nos. 2 and 3.


5.	South evaporation ponds Nos. 1, 2, 3, 4, and 5.


c.	Data Acquisition System


d.	Solid Waste Disposal Pit


e.	Coal pile runoff pond


13.	Coal Transfer Facilities from the Reclaim Conveyors to the Head-End of Plat Belts 4A and 4B and Dust Suppression Systems


14.	Maintenance Bay Facilities including: Bay Bridge Crane, all Offices, and Support Facilities

15. Sewage Treatment Facilities


16.	On each of Units 1 and 2, the Chemical Plant 165-pound Control Valve, and Branch Line from the Unit Specific 650-pound Rehear Steam Line


17.	On each of Units 3 and 4, the Chemical Plant Branch Steam Line from the Unit Specific Auxiliary Steam Header System

Exh. IV - 15

EXHIBIT IV(h)

SAN JUAN PROJECT

SWITCHYARD FACILITIES

Cost Allocation (%)



	Installed Cost		Replacements/Improvements Betterments
	PNM	TEP	PNM	TEP
345 kV Bus 1 & 3 (East Bus)	50	50	50	50
Bus 2 (West Bus)	50	50	50	50
Circuit Breakers
06582 (345/230)	50	50	50	50
5482	50	50	50	50
04382 (OJO)	50	50	50	50
12982 (McKinley)	50	50	50	50
11882	50	50	50	50
10782 (Unit 4)	50	50	50	50
09882 (McKinley)	58.33	41.67	62.5	37.5
8782	54.16	45.84	56.25	43.75
07682 (Unit 3)	50	50	50	50

15282 (Four Comers)	50	50	50	50
14182	50	50	50	50
13082 (Unit 2)	50	50	50	50

18582 (West Mesa)	50	50	50	50
17482	50	50	50	50
16382 (Unit 1)	50	50	50	50
20782	50	50	50	50
Shunt Reactors
Ojo	100	0	100	0
McKinley 1	5.36	94.64	5.36	94.64
McKinley 2	16.67	83.33	25	75
WW (BA)	100	0	100	0

EXHIBIT IV(h)

Exh. IV - 16

(continued)



	Installed Cost		Replacements/Improvements Betterments
	PNM	TEP	PNM	TEP
Transformers
Station Aux. No. 2 400 MVA, 345/230-12.5	100	0	100	0
Station Aux. No. 1 345/4.16-12.5	50	50	50	50
Station Aux. No. 3 90 MVA, 345/69-12.5	50	50	50	50

Future Facilities 345/69/12 kV	66.67	33.33	66.67	33.33
2-345 kV Bkrs (Durango)	50	50	50	50

Lower Voltage 230 kV Control Hse	83.33	16.67	83.33	16.67
230/69 kV Trf	66.67	33.33	66.67	33.33
Shiprock 230 kV line	100	0	100	0

Exh. IV - 17

EXHIBIT V

EXHIBIT V(a)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 1

Operation and Maintenance Costs



PNM -	50	%	TEP -	50	%
PNMR-D	0	%	Farmington -	0	%
UAMPS -	0	%	LAC -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment)


12.	Fly Ash System

Exh. V - 1

EXHIBIT V(a)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	SSR Protection System


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. V - 2

EXHIBIT V(b)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 2

Operation and Maintenance Costs



PNM -	50	%	TEP -	50	%
PNMR-D	0	%	Farmington -	0	%
UAMPS -	0	%	LAC -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers


11.	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment)


12.	Fly Ash System

Exh. V - 3

EXHIBIT V(b)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen

Exh. V - 4

EXHIBIT V(c)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 3

Operation and Maintenance Costs



PNM -	100	%	TEP -	0	%
PNMR-D	0	%	Farmington -	0	%
UAMPS -	0	%	LAC -	0	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 3A and 3B Transformers


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, and Pump House


12.	Fly Ash System

Exh. V - 5

EXHIBIT V(c)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the Reheat Steam Line from the Auxiliary Steam Header


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	SSR Protection System


20.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant

Exh. V - 6

EXHIBIT V(d)

FACILITIES AND EQUIPMENT

SPECIFIC TO SAN JUAN UNIT NO. 4

Operation and Maintenance Costs



PNM -	64.482	%	TEP -	0	%
PNMR-D	12.815	%	Farmington -	8.475	%
UAMPS -	7.028	%	LAC -	7.2	%


1.	Turbine Generator


2.	Condenser


3.	Condensate and Feedwater System


a.	Condensate Pumps


b.	Feedwater Heaters


c.	Boiler Feed Pumps


d.	Storage Tanks


4.	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks


5.	Forced Draft Fans and Primary Air Fans


6.	Precipitator


7.	Stack and Stack Monitoring System


8.	Cooling Tower


9.	Circulating Water Pumps


10.	Main, Unit Auxiliary 4A and 4B Transformers


11.	Bottom Ash System including: Hopper, Dewatering Tank, Setting Tank, Surge Tank, and Pump House


12.	Fly Ash System

Exh. V - 7

EXHIBIT V(d)

(continued)


13.	Building HVAC System


14.	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the Reheat Steam Line from the Auxiliary Steam Header


15.	Emergency Diesel Generator


16.	Electrical and Control Systems


17.	Fuel Oil Ignitor Heaters and Unit Specific Piping


18.	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen


19.	Auxiliary Steam Header Piping System:


a.	Including the Unit Specific Branch Line to the Reheat System


b.	Not included is the Branch Line to the Chemical Plant

Exh. V - 8

EXHIBIT V(e)

FACILITIES AND EQUIPMENT

COMMON TO SAN JUAN UNITS NO. 1 AND 2

Operation and Maintenance Costs



PNM -	50	%	TEP -	50	%
PNMR-D	0	%	Farmington -	0	%
UAMPS -	0	%	LAC -	0	%


1.	Bearing Cooling Water System except Unit Piping


2.	Bottom Ash Dewatering Facility including: Dewatering Tank, Settling Tank, Surge Tank, Storage Tank, and Pump House


3.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization)


4.	Instrument Air System, except Unit Piping


5.	Chemical Feed System, except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System


6.	Plant Air System, except Unit Piping


7.	Sootblowing Air System, except Unit Piping


8.	Hydrogen Storage System, except Unit Piping


9.	Coal Tripper System including Dust Collection System


10.	Turbine Lube Oil Storage and Transfer System


11.	Control Room, Equipment Rooms, and Associated HVAC System

Exh. V - 9

EXHIBIT V(e)

(continued)


12.	SO2 Backup Scrubber-Absorber Transformer


13.	Turbine Crane south of column, Line 12


14.	Fuel Oil, Ash, and Water Pipe Racks


15.	Boiler Fill System


16.	SAR Multiplexer Control System

Exh. V - 10

EXHIBIT V(f)

FACILITIES AND EQUIPMENT

COMMON TO SAN JUAN UNITS NO. 3 AND 4

Operation and Maintenance Costs



PNM -	64.482	%	TEP -	0	%
PNMR-D	12.815	%	Farmington -	8.475	%
UAMPS -	7.028	%	LAC-	7.2	%

1. Bearing Cooling Water System except Unit Piping


2.	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization except Ignitor Heaters and Unit Specific Piping)

3. Instrument Air System except Unit Piping

4. Chemical Feed System except Unit Piping


a.	Condensate and Feedwater System


b.	Boiler


c.	Bearing Cooling Water System


d.	Cooling Tower Systems


e.	Chlorination System

5. Plant Air System except Unit Piping

6. Sootblowing Air System except Unit Piping

7. Start-Up Transformers and Nonseg Bus to Units 3 and 4 Switchgear

8. Hydrogen Storage System except Unit Piping

9. Coal Tripper System including Dust Collection Systems

10. Turbine Lube Oil Storage and Transfer System

11. Control Room, Equipment Rooms, and Associated HVAC System

Exh. V - 11

EXHIBIT V(f)

(continued)

12. Boiler Fill System


13.	Auxiliary Cooling Systems including Auxiliary Cooling Tower No. 1 and Pumps, but excepting No. 4 Tower Pumps and Piping which is Unit Specific

14. CO2 Storage System except Unit Piping

15. Start-Up Boiler Feed Pump except Unit Piping

16. Turbine Bay Crane north of column, Line 12

17. Fuel Oil, Ash, and Water Pipe Racks

18. Fire Water Booster and Jockey Pumps

19. Halon Fire Protection System

20. Cooling Tower Multiplex Control System

Exh. V - 12

EXHIBIT V(g)

FACILITIES AND EQUIPMENT

COMMON TO ALL FOUR SAN JUAN UNITS

Operation and Maintenance Costs



PNM -	62.708	%	TEP -	19.8	%
PNMR-D	7.673	%	Farmington -	3.679	%
UAMPS -	3.017	%	LAC -	3.123	%


1.	River and Raw Water System including:


a.	Diversion and intake structures, including all equipment and pump building.


b.	Raw Water line to reservoir.


c.	Reservoir, pump buildings, and all equipment.


d.	Raw water lines to plant yard.


e.	All above and underground fire protection system to each vendor supplied or unit specific fire protection system.

2. Auxiliary Boiler

3. SO2 Removal System except Absorbers

3.1 SO2 Absorber Feed System


a.	Limestone Handling System


b.	Limestone Preparation System


c.	Dewatering System


d.	Gypsum Stack Out System

Exh. V - 13

EXHIBIT V(g)

(continued)

3.2 SO2 Chemical Plant

a. Double effect evaporator train systems.

b. Fly ash filter system.

c. Absorber product and feed tanks.

d. Condensate collection, storage, and transfer systems.

e. Soda ash storage, mixing, and distribution systems.


f.	Sulfate purge system including: crystallizers, centrifuges, evaporators, and salt cake system.

g. Sulfuric acid plant system including storage tanks and load out system.

h. Auxiliary No. 2 cooling tower, pumps, and systems.

4. Spare-Main Transformer 345/24 kV for all units.

5. Maintenance, Office, and Warehousing Facilities

6. Chemical Laboratory

7.* Coal and Ash Handling Control Facilities

8. Roads and grounds such as fencing, yard lighting, guard facilities, drainage, and dikes.

9. Potable Water System


10.	Environmental Monitoring systems including Air, Water, and Ground. Excludes Stack Monitoring Systems which are unit specific.

11. Transportation such as trucks, cars, and dozers (not otherwise charged).

12. Water Management System


a.	Wastewater Recovery System -- Northside


1.	Neutralization system including premix tank, neutralization tank, clarifier/thickener, and pumps.


2.	Reverse osmosis system including lime/soda softening clarifier system.


3.	Brine concentrator Nos. 4 and 5.


4.	Process pond No. 3 and pump system.


5.	North evaporation ponds 1, 2, and 3.

Exh. V - 14

EXHIBIT V(g)

(continued)


b.	SO2 Waste Treatment System -- Southside


1.	Process ponds 1A, 1B, 2 and pumping system.


2.	Premix tank and clarifier system.


3.	Oxidation towers.


4.	Brine concentrator Nos. 2 and 3.


5.	South evaporation ponds Nos. 1, 2, 3, 4, and 5.


c.	Data Acquisition System


d.	Solid Waste Disposal Pit


e.	Coal pile runoff pond


13.*	Coal Handling Equipment -- all equipment from all reclaim hoppers ending at the chutes to the tripper conveyors. This includes: hoppers. feeders. feeder belts, reclaim conveyors, plant conveyors, belt scales, fire protection systems, dust suppression systems, magnetic separators, all electrical and controls, and heating and ventilation systems.


14.	Maintenance Bay Facilities including: Bay Bridge Crane, all Offices, and Support Facilities

15. Sewage Treatment Facilities


16.	All Demineralizer Systems including: Clarifier, Storage Tanks, Sump Pumps, Filter Beds, and Control Systems.


17.	The Chemical Plant 165-pound Control Valve and Branch Line from each of Units 1 and 2 Unit Specific 650-pound Reheat Steam Line.


18.	The Chemical Plant Branch Steam Line from (but not including) the Unit Specific Auxiliary, Steam Header System on each of Units 3 and 4.

*Maintenance Only

Exh. V - 15

EXHIBIT V(h)

FACILITIES AND EQUIPMENT

COMMON TO ALL FOUR SAN JUAN UNITS

Operation Costs Only



PNM
TEP	Variable split based on generation by unit
Farmington
LAC
UAMPS PNMR-D

1. Coal and Ash Handling Control Facilities

2. Coal Handling Equipment

Exh. V - 16

EXHIBIT V(i)

SWITCHYARD FACILITIES AND EQUIPMENT

OPERATION AND MAINTENANCE COSTS



PNM - 65%	TEP - 35%

Exh. V - 17

EXHIBIT VI

San Juan Operating Agreement

Exhibit VI-Attachment A

A&G RATIO APPLICABLE TO OPERATION AND MAINTENANCE FOR THE SAN JUAN GENERATING STATION (“SJGS”)

The Operating Agent determines, in accordance with Accounting Practice, the appropriate A&G expense incurred for the benefit of the SJGS and to be billed to the SJGS as follows:

1. A&G expenses directly chargeable by on-site San Juan Project employees as set forth in Section 22.2.2;

2. A&G expenses directly chargeable by A&G related departments located off-site as set forth in Section 22.2.2; and

3. Indirect A&G expenses included in the development of the A&G ratio.

The FERC A&G accounts included in the A&G study are: 920, 921, 923, 930.2, 931 and 935.

Background

Exh. VI-1

The percentages derived from the questionnaires are then applied to the actual A&G amounts charged to the Bulk Power Business Unit for the study year. Amounts are split between labor and other.


B.	Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) (See Exhibit VI Attachments B, C and D) are applied to the labor portion of the A&G determined above.


C.	Other costs included in the development of the A&G Ratio are Depreciation of General Plant (FERC Account 403), Property Insurance (FERC Account 924) and Property Taxes (FERC Account 408) for the Operating Agent’s headquarters buildings and energy management facility and Amortization of Computer Software (FERC Account 404) for certain software applications that provide benefit to the SJGS.

The A&G ratio shall be applied to the following SJGS costs:


1)	Labor charged to the operation and maintenance expenses included in Sections 22.2.1, 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement. Such labor dollars are utilized as the denominator in the calculation of the A&G Ratio described below.

A&G Ratio = A/B

Exh. VI - 2

Where A = Administrative and general expense chargeable to FERC Accounts 920, 921,

B = Total SJGS operation and maintenance labor paid and accrued excluding labor expenses chargeable to FERC accounts 920 through 935 inclusive.

Exh. VI - 3

San Juan Operating Agreement

Exhibit VI-Attachment B

PAYROLL TAX RATIO FOR THE SAN JUAN GENERATING STATION (“SJGS”)

The Payroll Tax Ratio shall be applied to the following SJGS costs:


1)	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


2)	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.

Payroll Tax Ratio = T/P

Where T = The Operating Agent’s total payroll tax expense chargeable to FERC Account 408.

P = The Operating Agent’s total base labor paid and accrued, less wages paid for time-off allowances plus accruals for time-off allowances.


Notes: (1)	Base labor is defined as an employee’s hourly rate times the number of hours worked plus an accrual for time-off allowances. In addition, base labor also includes overtime pay and special pay.


(2)	Time-off allowances are defined as vacation, illness and holiday time.

Exh. VI - 4

San Juan Operating Agreement

Exhibit VI-Attachment C

INJURIES AND DAMAGES RATIO FOR THE

SAN JUAN GENERATING STATION (“SJGS”)

The Injuries and Damages Ratio shall be applied to the following SJGS costs:


1)	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


2)	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.

Injuries and Damages Ratio = I/P

Where I = The Operating Agent’s total injuries and damages expense chargeable to FERC Account 925, including payroll taxes, and pension and benefits on labor chargeable to FERC Account 925. The amount of payroll taxes and pension and benefits to be added are based on the ratios included in Exhibit VI, Attachments B and D, respectively. Note: Any injuries and damages expense charged direct to the SJGS are excluded from the determination of the Injuries and Damages Ratio.


Notes: (1)	Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay. Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan.

Exh. VI - 5

San Juan Operating Agreement

Exhibit VI-Attachment D

PENSION AND BENEFITS RATIO FOR THE

SAN JUAN GENERATING STATION (“SJGS”)

The Pension and Benefits Ratio shall be applied to the following SJGS costs:


1)	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


2)	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.

Pension and Benefits Ratio = B/P


Notes: (1)	Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay. Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan. Employee recognition awards are not eligible for pension and benefit loadings.

Exh. VI - 6

San Juan Operating Agreement

Exhibit VI-Attachment E

CAPITALIZED A&G RATIO APPLICABLE TO CAPITAL PROJECTS FOR THE SAN JUAN GENERATING STATION (“SJGS”)

The Operating Agent determines the appropriate A&G expense incurred for the benefit of the SJGS and to be billed to the SJGS as follows:

The FERC A&G accounts included in the A&G study are: 920, 921, 923, 930.2, 931 and 935.

Background


B.	Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) (see Exhibit VI Attachments B, C and D) are applied to the labor portion of the A&G determined above.

Exh. VI - 7

Capitalized A&G Ratio = A/B

B = Total SJGS capital project amounts for the Bulk Power Business Unit as categorized between major and minor construction projects for the study period chargeable to FERC Accounts 107 and 108.

Exh. VI - 8

EXHIBIT VII

[Omitted]

EXHIBIT VIII

Proportional Adjustment of Voting Requirements

in Case of a Default and Suspension of the Rights of a Participant

to Vote Pursuant to Section 35.4.1.

Example Calculation Based on Hypothetical Ownership Percentages:

Participation Shares for voting pursuant to Sections 18.4.1(a), 18.4.2(a), and 18.4.3(a) are adjusted as follows:

For Units:

The Adjusted Participation Share for a Participant = (That Participant’s Participation Share)/(The sum of the Participation Shares of all non-defaulting Participants in the affected Unit)

For Common Facilities:

Exh. VIII - 1



Unit or Facility	Original Participation Shares for Voting: §18.4.1(a), §18.4.2(a), and §18.4.3(a)		Original Number of Participants for Voting Purposes: §18.4.1(b), §18.4.2(b), and §18.4.3(b)	Adjusted Participation Shares for Voting - §18.4.1(a), §18.4.2(a), and §18.4.3(a)		Adjusted Number of Participants for Voting Purposes - §18.4.1(b), §18.4.2(b), and §18.4.3(b)
Unit 1			2			2
Participant A	50.00	%		50.00	%
Participant B	50.00	%		50.00	%
Unit 2			2			2
Participant A	50.00	%		50.00	%
Participant B	50.00	%		50.00	%
Unit 3			4			3
Participant A	20.00	%		28.57% ¹
Participant B	20.00	%		28.57	%
Participant C	30.00	%		42.86	%
Participant D	30.00	%		0.00	%
Unit 4			5			4
Participant A	10.00	%		12.50% ²
Participant B	10.00	%		12.50	%
Participant C	20.00	%		25.00	%
Participant D	20.00	%		0.00	%
Participant E	40.00	%		50.00	%
Unit 1 & 2 Common			2			2
Participant A	50.00	%		50.00	%
Participant B	50.00	%		50.00	%

_____________________________

¹ Computed on Unit 3 Participation Shares as follows: (Participant A) / (Participant A + Participant B + Participant C) = 20%/(20%+20%+30%) = 28.57%

² Computed on Unit 4 Participation Shares as follows: (Participant A) / (Participant A + Participant B + Participant C + Participant E) = 10%/(10%+10%+20%+40%) = 12.50%

Exh. VIII - 2



Unit 3 & 4 Common			5			4
Participant A	15.00	%		20.536% ³
Participant B	15.00	%		20.536%%
Participant C	25.00	%		33.928	%
Participant D	25.00	%		0.00	%
Participant E	20.00	%		25.000	%
Plant Common			5			4
Participant A	32.50	%		35.268% ⁴
Participant B	32.50	%		35.268	%
Participant C	12.50	%		16.964	%
Participant D	12.50	%		0.00	%
Participant E	10.00	%		12.500	%

_____________________________

³ Computed on Unit 3 and Unit 4 Common Participation Shares as follows: Unit 3

Contribution = (Participant A) / (Participant A + Participant B + Participant C) =

20%/(20%+20%+30%) = 28.571%; Unit 4 Contribution = (Participant A) / (Participant A

+ Participant B + Participant C + Participant E) = 10%/(10%+10%+20%+40%) =

12.500%.

Unit 3 & 4 Common = (Unit 3 Rating)/(Sum of Unit 3 and 4 Ratings) * (Unit 3

Contribution) + (Unit 4 Rating)/(Sum of Unit 3 and 4 Ratings) * (Unit 4 Contribution) =

1/2 (28.271%) + 1/2 (12.500%) = 20.536%

50.000%. Unit 3 Contribution = (Participant A) / (Participant A + Participant B +

Participant C) = 20%/(20%+20%+30%) = 28.571%; Unit 4 Contribution = (Participant

A) / (Participant A + Participant B + Participant C + Participant E) =

10%/(10%+10%+20%+40%) = 12.500%. Plant Common = (Unit 1 Rating)/(Plant

Rating) * (Unit 1 Contribution) + (Unit 2 Rating)/(Plant Rating) * (Unit 2 Contribution) + (Unit 3 Rating)/(Plant Rating) * (Unit 3 Contribution) + (Unit 4 Rating)/(Plant Rating) *

(Unit 4 Contribution) = 1/4 (50.000%) + 1/4 (50.000%) + 1/4 (28.571%) + (1/4 (12.5000%)

= 35.268%

Exh. VIII - 3

FOURTH AMENDMENT TO CREDIT AGREEMENT

THIS FOURTH AMENDMENT TO CREDIT AGREEMENT (this " Amendment ") is entered into as of September 9, 2015 among PNM RESOURCES, INC., a New Mexico corporation (the " Borrower "), the Lenders party hereto and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent for the Lenders (in such capacity, the " Administrative Agent "). Capitalized terms used herein and not otherwise defined shall have the meanings ascribed thereto in the Credit Agreement (as defined below).

R E C I T A L S

WHEREAS, the Borrower, the Lenders party thereto and the Administrative Agent are parties to that certain Credit Agreement, dated as of October 31, 2011 (as amended by the First Amendment to Credit Agreement, dated as of January 18, 2012, the Second Amendment to Credit Agreement, dated as of October 31, 2013, the Third Amendment, dated as of December 17, 2014 and as otherwise amended or modified from time to time, the " Credit Agreement ");

WHEREAS, the Borrower has requested a modification to the Credit Agreement as described below; and

WHEREAS, the Lenders party hereto are willing to agree to such modification, subject to the terms set forth herein as more fully set forth below.

NOW, THEREFORE, in consideration of the premises and the mutual covenants contained herein, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereto agree as follows:

A G R E E M E N T

1. Amendments to Credit Agreement .

(a) The first sentence of the definition of “Applicable Percentage” in Section 1.1 of the Credit Agreement is hereby amended to read as follows:

“ Applicable Percentage ” means, for Eurodollar Loans, LIBOR Market Index Rate Swing Line Loans, L/C Fees, Base Rate Loans and Commitment Fees, the appropriate applicable percentages, in each case (subject to the exception indicated below), corresponding to the Debt Rating of the Borrower in effect as of the most recent Calculation Date as shown below:

(b) The following definitions in Section 1.1 of the Credit Agreement are amended and restated in their entirety to read as follows:

" Change of Control " means the occurrence of any of the following: (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, but excluding any employee benefit plan of such person or its subsidiaries, and any person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan) becomes the "beneficial owner" (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934, except that a person or group shall be deemed to have "beneficial ownership" of all Capital Stock that such person or group has the right to acquire (such right, an " option right "), whether such right is exercisable immediately or only after the passage of time),

directly or indirectly, of twenty-five (25%) of the Capital Stock of the Borrower entitled to vote for members of the board of directors or equivalent governing body of the Borrower on a fully diluted basis (and taking into account all such securities that such person or group has the right to acquire pursuant to any option right); (b) during any period of 24 consecutive months, a majority of the members of the board of directors or other equivalent governing body of the Borrower cease to be composed of individuals (i) who were members of that board or equivalent governing body on the first day of such period, (ii) whose election or nomination to that board or equivalent governing body was approved by individuals referred to in clause (i) above constituting at the time of such election or nomination at least a majority of that board or equivalent governing body or (iii) whose election or nomination to that board or other equivalent governing body was approved by individuals referred to in clauses (i) and (ii) above constituting at the time of such election or nomination at least a majority of that board or equivalent governing body; or (c) any Person or two or more Persons acting in concert shall have acquired by contract or otherwise, or shall have entered into a contract or arrangement that, upon consummation thereof, will result in its or their acquisition of the power to exercise, directly or indirectly, a controlling influence over the management or policies of the Borrower, or control over the Voting Stock of the Borrower on a fully-diluted basis (and taking into account all such Voting Stock that such Person or group has the right to acquire pursuant to any option right) representing twenty-five (25%) or more of the combined voting power of such Voting Stock.

“ Debt Rating ” means, with respect to any Person, the long term, senior, unsecured non-credit enhanced debt rating of such Person by S&P or Moody’s, as applicable; provided, however, that if neither S&P nor Moody’s issues a long term, senior, unsecured non-credit enhanced rating of such Person, then (a) the Debt Rating shall be such Person’s issuer corporate credit rating by S&P or Moody’s, as applicable, and (b) for purposes of determining the applicable pricing level in the definition of Applicable Percentage, the Debt Rating of the Borrower shall be deemed to be the lesser of (x) the actual Debt Rating of the Borrower and (y) one level lower than the Debt Rating of PSNM (e.g., if the Debt Rating of PSNM by S&P is BBB then the Debt Rating of the Borrower by S&P pursuant to this clause (b) can be no greater than BBB-).

2. Effectiveness; Conditions Precedent .

This Amendment shall be effective on the date upon receipt by the Administrative Agent of copies of this Amendment duly executed by the Borrower and the Required Lenders.

3. Ratification of Credit Agreement . The term "Credit Agreement" as used in each of the Credit Documents shall hereafter mean the Credit Agreement as amended and modified by this Amendment. Except as herein specifically agreed, the Credit Agreement, as amended by this Amendment, is hereby ratified and confirmed and shall remain in full force and effect according to its terms. Each party hereto acknowledges and consents to the modifications set forth herein and agrees that, other than as explicitly set forth in Section 1 above, this Amendment does not impair, reduce or limit any of its obligations under the Credit Documents (including, without limitation, the indemnity obligations set forth therein) and that, after the date hereof, this Amendment shall constitute a Credit Document. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Credit Documents or constitute a waiver of any provision of any of the Credit Documents.

4. Authority/Enforceability . The Borrower represents and warrants as follows:

(a) It has taken all necessary action to authorize the execution, delivery and performance of this Amendment.

(b) This Amendment has been duly executed and delivered by the Borrower and constitutes the Borrower’s legal, valid and binding obligations, enforceable in accordance with its terms, except as such enforceability may be subject to (i) bankruptcy, insolvency, reorganization, fraudulent conveyance or transfer, moratorium or similar laws affecting creditors' rights generally and (ii) general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

(c) No consent, approval, authorization or order of, or filing, registration or qualification with, any court or governmental authority or third party is required in connection with the execution, delivery or performance by the Borrower of this Amendment.

5. Representations and Warranties . The Borrower represents and warrants to the Lenders that (a) the representations and warranties of the Borrower set forth in Section 6 of the Credit Agreement are true and correct as of the date hereof, unless they specifically refer to an earlier date and except that, for purposes of the foregoing, the references to “December 31, 2013” in Section 6.7(a) of the Credit Agreement are hereby amended to “December 31, 2014,” (b) no event has occurred and is continuing which constitutes a Default or an Event of Default, and (c) it has no claims, counterclaims, offsets, credits or defenses to its obligations under the Credit Documents, or to the extent it has any, they are hereby released in consideration of the Lenders party hereto entering into this Amendment.

6. No Conflicts . The Borrower represents and warrants that the execution and delivery of this Amendment, the consummation of the transactions contemplated herein and in the Credit Agreement (before and after giving effect to this Amendment), and the performance of and compliance with the terms and provisions hereof by the Borrower will not (a) violate, contravene or conflict with any provision of its articles or certificate of incorporation, bylaws or other organizational or governing document, (b) violate, contravene or conflict with any law, rule, regulation (including, without limitation, Regulation U and Regulation X), order, writ, judgment, injunction, decree or permit applicable to the Borrower, (c) violate, contravene or conflict with contractual provisions of, or cause an event of default under, any indenture, loan agreement, mortgage, deed of trust, contract or other agreement or instrument to which the Borrower is a party or by which it or its properties may be bound, the violation of which would have or would reasonably be expected to have a Material Adverse Effect or (d) result in or require the creation of any Lien upon or with respect to the Borrower's properties.

7. Counterparts/Telecopy . This Amendment may be executed in any number of counterparts, each of which when so executed and delivered shall be an original, but all of which shall constitute one and the same instrument. Delivery of executed counterparts by telecopy or by electronic format (pdf) shall be effective as an original.

8. GOVERNING LAW . THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

[remainder of page intentionally left blank]

Each of the parties hereto has caused a counterpart of this Amendment to be duly executed and delivered as of the date first above written.

BORROWER :

PNM RESOURCES, INC. ,

a New Mexico corporation

By: /s/ Elisabeth Eden

Name: Elisabeth Eden

Title: Vice President & Treasurer

ADMINISTRATIVE AGENT :

WELLS FARGO BANK, NATIONAL ASSOCIATION ,

as Administrative Agent, as a Lender and as an L/C Issuer

By: /s/ Gregory R. Gredvig

Name: Gregory R. Gredvig

Title: Vice President

LENDERS :

MUFG UNION BANK, N.A.,

as a Lender and an L/C Issuer

By: /s/ Paul V. Farrell

Name: Paul V. Farrell

Title: Managing Director

CITIBANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

JPMORGAN CHASE BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

MORGAN STANLEY BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

ROYAL BANK OF CANADA,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

SUNTRUST BANK,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

LENDERS :

MUFG UNION BANK, N.A.,

as a Lender and an L/C Issuer

By:_____________________________________

Name:___________________________________

Title:____________________________________

CITIBANK, N.A.,

as a Lender

By: /s/ Damien Lipke

Name: Damien Lipke

Title: Vice President

JPMORGAN CHASE BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

MORGAN STANLEY BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

ROYAL BANK OF CANADA,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

SUNTRUST BANK,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

LENDERS :

MUFG UNION BANK, N.A.,

as a Lender and an L/C Issuer

By:_____________________________________

Name:___________________________________

Title:____________________________________

CITIBANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

JPMORGAN CHASE BANK, N.A.,

as a Lender

By: /s/ Helen D. Davis

Name: Helen D. Davis

Title: Vice President

MORGAN STANLEY BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

ROYAL BANK OF CANADA,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

SUNTRUST BANK,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

LENDERS :

MORGAN STANLEY BANK, N.A.,

as a Lender

By: /s/ Dmitriy Barskiy

Name: Dmitriy Barskiy

Title: Authorized Signatory

LENDERS :

MUFG UNION BANK, N.A.,

as a Lender and an L/C Issuer

By:_____________________________________

Name:___________________________________

Title:____________________________________

CITIBANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

JPMORGAN CHASE BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

MORGAN STANLEY BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

ROYAL BANK OF CANADA,

as a Lender

By: /s/ Ben Thomas

Name: Ben Thomas

Title: Authorized Signatory

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

SUNTRUST BANK,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

LENDERS :

MUFG UNION BANK, N.A.,

as a Lender and an L/C Issuer

By:_____________________________________

Name:___________________________________

Title:____________________________________

CITIBANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

JPMORGAN CHASE BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

MORGAN STANLEY BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

ROYAL BANK OF CANADA,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By: /s/ Keven D Smith

Name: Keven D Smith

Title: Senior Vice President

SUNTRUST BANK,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

LENDERS :

MUFG UNION BANK, N.A.,

as a Lender and an L/C Issuer

By:_____________________________________

Name:___________________________________

Title:____________________________________

CITIBANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

JPMORGAN CHASE BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

MORGAN STANLEY BANK, N.A.,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

ROYAL BANK OF CANADA,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

KEYBANK NATIONAL ASSOCIATION,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

SUNTRUST BANK,

as a Lender

By: /s/ Andrew Johnson

Name: Andrew Johnson

Title: Director

U.S. BANK, NATIONAL ASSOCIATION,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

THE BANK OF NEW YORK MELLON,

as a Lender

By: /s/ Mark W. Rogers

Name: Mark W. Rogers

Title: Vice President

BOKF, d/b/a BANK OF ALBUQUERQUE,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

U.S. BANK, NATIONAL ASSOCIATION,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

THE BANK OF NEW YORK MELLON,

as a Lender

By:_____________________________________

Name:___________________________________

Title:____________________________________

BOKF NA, d/b/a BANK OF ALBUQUERQUE,

as a Lender

By: /s/ John Valentine

Name: John Valentine

Title: SVP

FIRST AMENDMENT TO TERM LOAN AGREEMENT

THIS FIRST AMENDMENT TO TERM LOAN AGREEMENT (this " Amendment ") is entered into as of September 9, 2015 among PNM RESOURCES, INC., a New Mexico corporation (the " Borrower "), the Lenders party hereto and WELLS FARGO BANK, NATIONAL ASSOCIATION, as Administrative Agent for the Lenders (in such capacity, the " Administrative Agent "). Capitalized terms used herein and not otherwise defined shall have the meanings ascribed thereto in the Loan Agreement (as defined below).

R E C I T A L S

WHEREAS, the Borrower, the Lenders party thereto and the Administrative Agent are parties to that certain Term Loan Agreement, dated as of March 9, 2015 (as amended or modified from time to time, the " Loan Agreement ");

WHEREAS, the Borrower has requested a modification to the Loan Agreement as described below; and

WHEREAS, the Lenders party hereto are willing to agree to such modification, subject to the terms set forth herein as more fully set forth below.

A G R E E M E N T

1. Amendments to Loan Agreement .

(a) The first sentence of the definition of “Applicable Percentage” in Section 1.1 of the Loan Agreement is hereby amended to read as follows:

“ Applicable Percentage ” means, for Eurodollar Loans, Base Rate Loans and Commitment Fees, the appropriate applicable percentages, in each case (subject to the exception indicated below), corresponding to the Debt Rating of the Borrower in effect as of the most recent Calculation Date as shown below:

(b) The following definition in Section 1.1 of the Loan Agreement is amended and restated in its entirety to read as follows:

2. Effectiveness; Conditions Precedent .

This Amendment shall be effective on the date upon receipt by the Administrative Agent of copies of this Amendment duly executed by the Borrower and the Required Lenders.

3. Ratification of Loan Agreement . The term "Loan Agreement" as used in each of the Loan Documents shall hereafter mean the Loan Agreement as amended and modified by this Amendment. Except as herein specifically agreed, the Loan Agreement, as amended by this Amendment, is hereby ratified and confirmed and shall remain in full force and effect according to its terms. Each party hereto acknowledges and consents to the modifications set forth herein and agrees that, other than as explicitly set forth in Section 1 above, this Amendment does not impair, reduce or limit any of its obligations under the Loan Documents (including, without limitation, the indemnity obligations set forth therein) and that, after the date hereof, this Amendment shall constitute a Loan Document. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents or constitute a waiver of any provision of any of the Loan Documents.

4. Authority/Enforceability . The Borrower represents and warrants as follows:

(a) It has taken all necessary action to authorize the execution, delivery and performance of this Amendment.

5. Representations and Warranties . The Borrower represents and warrants to the Lenders that (a) the representations and warranties of the Borrower set forth in Section 6 of the Loan Agreement are true and correct as of the date hereof, unless they specifically refer to an earlier date, (b) no event has occurred and is continuing which constitutes a Default or an Event of Default, and (c) it has no claims, counterclaims, offsets, credits or defenses to its obligations under the Loan Documents, or to the extent it has any, they are hereby released in consideration of the Lenders party hereto entering into this Amendment.

6. No Conflicts . The Borrower represents and warrants that the execution and delivery of this Amendment, the consummation of the transactions contemplated herein and in the Loan Agreement (before and after giving effect to this Amendment), and the performance of and compliance with the terms and provisions hereof by the Borrower will not (a) violate, contravene or conflict with any provision of its articles or certificate of incorporation, bylaws or other organizational or governing document, (b) violate, contravene or conflict with any law, rule, regulation (including, without limitation, Regulation U and Regulation X), order, writ, judgment, injunction, decree or permit applicable to the Borrower, (c) violate, contravene or conflict with contractual provisions of, or cause an event of default under, any indenture, loan agreement, mortgage, deed of trust, contract or other agreement or instrument

to which the Borrower is a party or by which it or its properties may be bound, the violation of which would have or would reasonably be expected to have a Material Adverse Effect or (d) result in or require the creation of any Lien upon or with respect to the Borrower's properties.

8. GOVERNING LAW . THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.

[remainder of page intentionally left blank]

Each of the parties hereto has caused a counterpart of this Amendment to be duly executed and delivered as of the date first above written.

BORROWER :

PNM RESOURCES, INC. ,

a New Mexico corporation

By: /s/ Elisabeth Eden

Name: Elisabeth Eden

Title: Vice President & Treasurer

ADMINISTRATIVE AGENT :

WELLS FARGO BANK, NATIONAL ASSOCIATION ,

as Administrative Agent and a Lender

By: /s/ Gregory R. Gredvig

Name: Gregory R. Gredvig

Title: Vice President

LENDERS :

ROYAL BANK OF CANADA,

as a Lender

By: /s/ Ben Thomas

Name: Ben Thomas

Title: Authorized Signatory

SUNTRUST BANK,

as a Lender

By:____________________________________

Name:__________________________________

Title:___________________________________

U.S. BANK NATIONAL ASSOCIATION,

as a Lender

By:____________________________________

Name:__________________________________

Title:___________________________________

LENDERS :

ROYAL BANK OF CANADA,

as a Lender

By:____________________________________

Name:__________________________________

Title:___________________________________

SUNTRUST BANK,

as a Lender

By: /s/ Andrew Johnson

Name: Andrew Johnson

Title: Director

U.S. BANK NATIONAL ASSOCIATION,

as a Lender

By:____________________________________

Name:__________________________________

Title:___________________________________



Exhibit 12.1
PNM RESOURCES, INC. AND SUBSIDIARIES
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)

	Nine Months Ended				Year Ended December 31,
	September 30, 2015				2014				2013				2012			2011				2010
Fixed charges, as defined by the Securities and Exchange Commission:

Interest expensed and capitalized	$	88,100			$	117,337			$	118,880			$	125,379		$	122,998			$	123,633
Amortization of debt premium, discount, and expenses	2,730				4,194				3,716				4,023			3,695				4,627
Estimated interest factor of lease rental charges	2,557				4,686				5,847				5,585			6,665				6,888
Preferred dividend requirements of subsidiary	602				809				800				769			864				1,075
Total Fixed Charges	$	93,989			$	127,026			$	129,243			$	135,756		$	134,222			$	136,223

Earnings, as defined by the Securities and Exchange Commission:

Earnings (loss) from continuing operations before income taxes and non-controlling interest	$	179,984			$	200,647			$	175,069			$	175,035		$	321,469			$	(63,379	)
(Earnings) loss of equity investee	—				—				—				—			—				15,223
Earnings (loss) from continuing operations before income taxes, non-controlling interest, and investee earnings	179,984				200,647				175,069				175,035			321,469				(48,156		)
Fixed charges as above	93,989				127,026				129,243				135,756			134,222				136,223
Interest capitalized	(6,450		)		(6,256		)		(5,209		)		(5,432		)	(2,697		)		(3,401		)
Non-controlling interest in earnings of Valencia	(10,909		)		(14,127		)		(14,521		)		(14,050		)	(14,047		)		(13,563		)
Preferred dividend requirements of subsidiary	(602		)		(809		)		(800		)		(769		)	(864		)		(1,075		)
Earnings Available for Fixed Charges	$	256,012			$	306,481			$	283,782			$	290,540		$	438,083			$	70,028

Ratio of Earnings to Fixed Charges	2.72			¹	2.41			²	2.20			²	2.14			3.26			³	0.51			⁴

¹ Earnings (loss) from continuing operations before income taxes and non-controlling interest for the nine months ended September 30, 2015 includes a pre-tax loss of $1.7 million due to the write-off of regulatory disallowances at PNM. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.74.

² Earnings (loss) from continuing operations before income taxes and non-controlling interest for the years ended December 31, 2014 and December 31, 2013 includes pre-tax losses of $1.1 million and $12.2 million due to the write-off of regulatory disallowances at PNM. If those losses were excluded, the Ratio of Earnings to Fixed Charges would have been 2.42 for 2014 and 2.29 for 2013.

³ Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes pre-tax losses of $21.4 million due to the write-off of regulatory disallowances at PNM and TNMP. If those losses were excluded, the Ratio of Earnings to Fixed Charges would have been 3.42. In addition, 2011 includes a pre-tax gain on the sale of First Choice of $174.9 million. If that gain were also excluded, the Ratio of Earnings to Fixed Charges would have been 1.96.

⁴ The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $66.2 million for the year ended December 31, 2010. Earnings (loss) from continuing operations before income taxes and non-controlling interest includes a pre-tax loss of $188.2 million due to the impairment of PNMR's investment in an equity investee. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 1.90.



Exhibit 12.2
PUBLIC SERVICE COMPANY OF NEW MEXICO
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)

	Nine Months Ended				Year Ended December 31,
	September 30, 2015				2014				2013				2012			2011				2010
Fixed charges, as defined by the Securities and Exchange Commission:

Interest expensed and capitalized	$	62,245			$	79,834			$	79,769			$	82,864		$	75,217			$	73,423
Amortization of debt premium, discount and expenses	1,498				1,944				1,879				1,818			1,325				1,274
Estimated interest factor of lease rental charges	1,181				2,541				3,732				3,743			4,139				4,103
Total Fixed Charges	$	64,924			$	84,319			$	85,380			$	88,425		$	80,681			$	78,800

Earnings, as defined by the Securities and Exchange Commission:

Earnings from continuing operations before income taxes and non-controlling interest	$	136,483			$	154,086			$	151,480			$	156,314		$	105,965			$	107,288
Fixed charges as above	64,924				84,319				85,380				88,425			80,681				78,800
Non-controlling interest in earnings of Valencia	(10,909		)		(14,127		)		(14,521		)		(14,050		)	(14,047		)		(13,563		)
Interest capitalized	(5,626		)		(5,211		)		(4,420		)		(4,314		)	(1,761		)		(2,811		)

Earnings Available for Fixed Charges	$	184,872			$	219,067			$	217,919			$	226,375		$	170,838			$	169,714

Ratio of Earnings to Fixed Charges	2.85			¹	2.60			²	2.55			²	2.56			2.12			³	2.15

¹ Earnings (loss) from continuing operations before income taxes and non-controlling interest for the nine months ended June 30, 2015 includes a pre-tax loss of $1.7 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.87.

² Earnings (loss) from continuing operations before income taxes and non-controlling interest for the years ended December 31, 2014 and December 31, 2013 include pre-tax losses of $1.1 million and $12.2 million due to the write-off of regulatory disallowances. If these losses were excluded, the Ratio of Earnings to Fixed Charges would have been 2.61 for 2014 and 2.70 for 2013.

³ Earnings (loss) from continuing operations before income taxes and non-controlling interest for the year ended December 31, 2011 includes a pre-tax loss $17.5 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.33.



Exhibit 12.3
TEXAS-NEW MEXICO POWER COMPANY
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)


	Nine Months Ended			Year Ended December 31,
	September 30, 2015			2014			2013			2012			2011				2010
Fixed charges, as defined by the Securities and Exchange Commission:

Interest expensed and capitalized	$	19,345		$	24,941		$	24,481		$	26,233		$	27,914			$	28,632
Amortization of debt premium, discount and expenses	814			1,195			1,159			1,493			1,679				2,683
Estimated interest factor of lease rental charges	920			1,311			1,241			956			1,202				1,246

Total Fixed Charges	$	21,079		$	27,447		$	26,881		$	28,682		$	30,795			$	32,561


Earnings, as defined by the Securities and Exchange Commission:

Earnings from continuing operations before income taxes	$	52,448		$	60,330		$	46,711		$	42,099		$	36,138			$	26,026
Fixed charges as above	21,079			27,447			26,881			28,682			30,795				32,561
Interest capitalized	(497		)	(609		)	(361		)	(706		)	(593		)		(158		)

Earnings Available for Fixed Charges	$	73,030		$	87,168		$	73,231		$	70,075		$	66,340			$	58,429

Ratio of Earnings to Fixed Charges	3.46			3.18			2.72			2.44			2.15			¹	1.79

¹ Earnings from continuing operations before income taxes for the year ended December 31, 2011 includes a pre-tax loss of $3.9 million due to the write-off of regulatory disallowances. If that loss were excluded, the Ratio of Earnings to Fixed Charges would have been 2.28.

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.1

CERTIFICATION

I, Patricia K. Collawn, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	October 30, 2015	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			PNM Resources, Inc.

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.2

CERTIFICATION

I, Charles N. Eldred, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of PNM Resources, Inc.;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	October 30, 2015	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			PNM Resources, Inc.

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.3

CERTIFICATION

I, Patricia K. Collawn, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	October 30, 2015	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			Public Service Company of New Mexico

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 31.4

CERTIFICATION

I, Charles N. Eldred, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Public Service Company of New Mexico;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	October 30, 2015	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			Public Service Company of New Mexico

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.5

CERTIFICATION

I, Patricia K. Collawn, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	October 30, 2015	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 31.6

CERTIFICATION

I, Charles N. Eldred, certify that:


1.	I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (each registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	October 30, 2015	By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer
			Texas-New Mexico Power Company

PNM Resources

414 Silver Ave. SW

Albuquerque, NM 87102-3289

www.pnmresources.com

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2015 , for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on October 30, 2015 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:


(1)	the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	October 30, 2015	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			PNM Resources, Inc.

		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

Public Service Company of New Mexico

414 Silver Ave. SW

Albuquerque, NM 87102-3289

EXHIBIT 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2015 , for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on October 30, 2015 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that:


(1)	the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	October 30, 2015	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			President and Chief Executive Officer
			Public Service Company of New Mexico

		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer

Texas-New Mexico Power Company

577 N. Garden Ridge Blvd.

Lewisville, Texas 75067

EXHIBIT 32.3

CERTIFICATION PURSUANT TO 18 U.S.C. § 1350, AS ADOPTED PURSUANT TO § 906 OF THE

SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report on Form 10-Q for the period ended September 30, 2015 , for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on October 30, 2015 (“Report”), each of the undersigned officers of the Company certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:


(1)	the Report fully complies with the requirements of § 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and


(2)	the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.



Date:	October 30, 2015	By:	/s/ Patricia K. Collawn
			Patricia K. Collawn
			Chief Executive Officer
			Texas-New Mexico Power Company

		By:	/s/ Charles N. Eldred
			Charles N. Eldred
			Executive Vice President and
			Chief Financial Officer