TEXAS NEW MEXICO POWER CO (Form: 10-Q, Received: 05/07/2010 13:20:18)

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 March 31, 2010



Commission	Name of Registrants, State of Incorporation,	I.R.S. Employer
File Number	Address and Telephone Number	Identification No.
001-32462	PNM Resources, Inc.	85-0468296
	(A New Mexico Corporation)
	Alvarado Square
	Albuquerque, New Mexico 87158
	(505) 241-2700

001-06986	Public Service Company of New Mexico	85-0019030
	(A New Mexico Corporation)
	Alvarado Square
	Albuquerque, New Mexico 87158
	(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 PNM Resources, Inc. (“PNMR”) and Public Service Company of New Mexico (“PNM”) (1) have 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) have been subject to such filing requirements for the past 90 days. YES ü NO

Indicate by check mark whether Texas-New Mexico Power Company (“TNMP”) (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. 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 the registrants have submitted electronically and posted on its corporate Web sites, 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). YES___ NO___ (No Interactive Data Files required to be submitted)

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

Large accelerated filer ü

Accelerated filer

Non-accelerated filer

Indicate by check mark whether each of PNM and TNMP is a large accelerated filer, accelerated filer, or non-accelerated filer (as defined in Rule 12b-2 of the Act).

Large accelerated filer

Accelerated filer

Non-accelerated filer ü

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 April 30, 2010, 86,673,174 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 April 30, 2010 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 April 30, 2010 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.

PNM RESOURCES, INC. AND SUBSIDIARIES

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARY

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 (Loss)	6
Condensed Consolidated Balance Sheets	7
Condensed Consolidated Statements of Cash Flows	9
Condensed Consolidated Statements of Changes in PNMR Common Stockholders’ Equity	11
Condensed Consolidated Statements of Comprehensive Income (Loss)	12
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	13
Condensed Consolidated Balance Sheets	14
Condensed Consolidated Statements of Cash Flows	16
Condensed Consolidated Statements of Changes in PNM Common Stockholder’s Equity	18
Condensed Consolidated Statements of Comprehensive Income	19
TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES
Condensed Consolidated Statements of Earnings	20
Condensed Consolidated Balance Sheets	21
Condensed Consolidated Statements of Cash Flows	23
Condensed Consolidated Statements of Changes in Common Stockholder’s Equity	25
Condensed Consolidated Statements of Comprehensive Income	26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS	27
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION	69
AND RESULTS OF OPERATIONS
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	91
ITEM 4. CONTROLS AND PROCEDURES	96
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS	97
ITEM 1A. RISK FACTORS	97
ITEM 6. EXHIBITS	98
SIGNATURE	100

GLOSSARY

Definitions:
Afton		Afton Generating Station
AG		New Mexico Attorney General
ALJ		Administrative Law Judge
Altura		Optim Energy Twin Oaks, LP
Altura Cogen		Optim Energy Altura Cogen, LLC (the CoGen Lyondell Power Generation Facility)
AOCI		Accumulated Other Comprehensive Income
APS		Arizona Public Service Company, which is the operator and a co-owner of PVNGS and Four Corners
BART		Best Available Retrofit Technology
BHP		BHP Billiton, Ltd, the parent of SJCC
Board		Board of Directors of PNMR
BTU		British Thermal Unit
Cal PX		California Power Exchange
Cal ISO		California Independent System Operator
Cascade		Cascade Investment, L.L.C.
CCB		Coal Combustion Byproducts
Continental		Continental Energy Systems, L.L.C.
CRHC		Cap Rock Holding Corporation, a subsidiary of Continental
CTC		Competition Transition Charge
Decatherm		Million BTUs
Delta		Delta-Person Limited Partnership
DOE		Department of Energy
ECJV		ECJV Holdings, LLC
EIP		Eastern Interconnection Project
EPA		United States Environmental Protection Agency
EPE		El Paso Electric
ERCOT		Electric Reliability Council of Texas
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
First Choice		First Choice Power, L. P. and Subsidiaries
Four Corners		Four Corners Power Plant
FPPAC		Fuel and Purchased Power Adjustment Clause
GAAP		Generally Accepted Accounting Principles in the United States of America
GEaR		Gross Earnings at Risk
GHG		Greenhouse Gas Emissions
GWh		Gigawatt hours
IBEW		International Brotherhood of Electrical Workers, Local 611
ISO		Independent System Operator
KWh		Kilowatt Hour
LBB		Lehman Brothers Bank, FSB, a subsidiary of LBH
LBH		Lehman Brothers Holdings Inc.
LCC		Lyondell Chemical Company
LIBOR		London Interbank Offered Rate
Lordsburg		Lordsburg Generating Station
Luna		Luna Energy Facility
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
Moody’s		Moody’s Investor Services, Inc.
MW		Megawatt
MWh		Megawatt Hour
Navajo Acts		Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act, and the Navajo Nation Pesticide Act
NDT		Nuclear Decommissioning Trusts for PVNGS
Ninth Circuit		United States Court of Appeals for the Ninth Circuit
NMGC		New Mexico Gas Company, a subsidiary of Continental
NMED		New Mexico Environment Department
NMPRC		New Mexico Public Regulation Commission

NO X		Nitrogen Oxide
NOI		Notice of Inquiry
NRC		United States Nuclear Regulatory Commission
NSR		New Source Review
O&M		Operations and Maintenance
OCI		Other Comprehensive Income
Optim Energy		Optim Energy, LLC, a limited liability company, owned 50% by each of PNMR and ECJV
PBO		Projected Benefit Obligation
PCRBs		Pollution Control Revenue Bonds
PGAC		Purchased Gas Adjustment Clause
PG&E		Pacific Gas and Electric Co.
PNM		Public Service Company of New Mexico and Subsidiaries
PNM Facility		PNM’s $400 Million Unsecured Revolving Credit Facility
PNMR		PNM Resources, Inc. and Subsidiaries
PNMR Facility		PNMR’s $600 Million Unsecured Revolving Credit Facility
PPA		Power Purchase Agreement
PRP		Potential Responsible Party
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas
PV		Photovoltaic
PVNGS		Palo Verde Nuclear Generating Station
RCRA		Resource Conservation and Recovery Act
RCT		Reasonable Cost Threshold
REC		Renewable Energy Certificates
REP		Retail Electricity Provider
RMC		Risk Management Committee
SCE		Southern Cal Edison Company
SEC		United States Securities and Exchange Commission
SJCC		San Juan Coal Company, a subsidiary of BHP
SJGS		San Juan Generating Station
SO 2		Sulfur Dioxide
SPS		Southwestern Public Service Company
SRP		Salt River Project
S&P		Standard and Poor’s Ratings Services
TECA		Texas Electric Choice Act
Term Loan Agreement		PNM’s $300 Million Unsecured Delayed Draw Term Loan Facility
TNMP		Texas-New Mexico Power Company and Subsidiaries
TNMP Revolving Credit Facility		TNMP’s $75 Million Unsecured Revolving Credit Facility
Twin Oaks		Assets of Twin Oaks Power, L.P. and Twin Oaks Power III, L.P.
Valencia		Valencia Energy Facility
VaR		Value at Risk

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS (LOSS)

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands, except per share amounts)
Operating Revenues:
Electric	$	383,396		$	385,803
Other		61			62
Total operating revenues		383,457			385,865

Operating Expenses:
Cost of energy		190,888			181,248
Administrative and general		62,785			62,138
Energy production costs		53,885			48,557
Depreciation and amortization		37,279			36,071
Transmission and distribution costs		13,890			14,017
Taxes other than income taxes		14,187			13,931
Total operating expenses		372,914			355,962
Operating income		10,543			29,903

Other Income and Deductions:
Interest income		5,027			5,223
Gains (losses) on investments held by NDT		1,743			(4,382	)
Other income		10,137			23,164
Equity in net earnings (loss) of Optim Energy		(4,352	)		1,395
Other deductions		(1,841	)		(2,360	)
Net other income (deductions)		10,714			23,040

Interest Charges		31,410			28,949

Earnings (Loss) before Income Taxes		(10,153	)		23,994

Income Taxes (Benefit)		(4,939	)		7,587

Earnings (Loss) from Continuing Operations		(5,214	)		16,407

Earnings from Discontinued Operations, net of Income
Taxes of $0 and $40,027		-			75,853

Net Earnings (Loss)		(5,214	)		92,260

Earnings Attributable to Valencia Non-controlling Interest		(3,103	)		(2,579	)

Preferred Stock Dividend Requirements of Subsidiary		(132	)		(132	)

Net Earnings (Loss) Attributable to PNMR	$	(8,449	)	$	89,549

Earnings (Loss) from Continuing Operations Attributable to PNMR per Common Share:
Basic	$	(0.09	)	$	0.15
Diluted	$	(0.09	)	$	0.15
Net Earnings (Loss) Attributable to PNMR per Common Share:
Basic	$	(0.09	)	$	0.98
Diluted	$	(0.09	)	$	0.98

Dividends Declared per Common Share	$	0.125		$	0.125

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

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,		December 31,
	2010		2009
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	28,986	$	14,641
Special deposits		31,962		52
Accounts receivable, net of allowance for uncollectible accounts of $11,415 and $12,783		100,956		106,593
Unbilled revenues		61,399		78,274
Other receivables		79,847		77,672
Materials, supplies, and fuel stock		50,532		50,631
Regulatory assets		18,976		7,476
Commodity derivative instruments		61,783		50,619
Income taxes receivable		127,597		129,171
Other current assets		90,758		63,076

Total current assets		652,796		578,205

Other Property and Investments:
Investment in PVNGS lessor notes		121,796		137,511
Equity investment in Optim Energy		193,589		195,666
Investments held by NDT		141,237		137,032
Other investments		24,645		25,528
Non-utility property, net of accumulated depreciation of $3,999 and $3,779		7,704		7,923

Total other property and investments		488,971		503,660

Utility Plant:
Plant in service and plant held for future use		4,735,674		4,693,530
Less accumulated depreciation and amortization		1,628,167		1,611,496
		3,107,507		3,082,034
Construction work in progress		166,198		181,078
Nuclear fuel, net of accumulated amortization of $23,830 and $19,456		75,473		69,337

Net utility plant		3,349,178		3,332,449

Deferred Charges and Other Assets:
Regulatory assets		525,056		524,136
Goodwill		321,310		321,310
Other intangible assets, net of accumulated amortization of $5,314 and $5,272		26,525		26,567
Commodity derivative instruments		3,779		2,413
Other deferred charges		92,775		71,181

Total deferred charges and other assets		969,445		945,607
	$	5,460,390	$	5,359,921

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

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
	2010			2009
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	287,973		$	198,000
Current installments of long-term debt		2,125			2,125
Accounts payable		103,354			111,432
Accrued interest and taxes		66,717			45,341
Regulatory liabilities		1,701			908
Commodity derivative instruments		59,944			24,025
Other current liabilities		152,114			181,442

Total current liabilities		673,928			563,273

Long-term Debt		1,565,366			1,565,206

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		528,773			531,166
Accumulated deferred investment tax credits		19,911			20,518
Regulatory liabilities		354,503			350,324
Asset retirement obligations		72,418			70,963
Accrued pension liability and postretirement benefit cost		275,681			281,923
Commodity derivative instruments		12,133			4,549
Other deferred credits		124,611			121,394

Total deferred credits and other liabilities		1,388,030			1,380,837

Total liabilities		3,627,324			3,509,316

Commitments and Contingencies (See Note 9)

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 Convertible Preferred Stock, Series A without mandatory redemption requirements
(no stated value, 10,000,000 shares authorized: issued and outstanding 477,800 shares)		100,000			100,000
PNMR common stockholders’ equity:
Common stock outstanding (no par value, 120,000,000 shares authorized: issued
and outstanding 86,673,174 shares)		1,290,248			1,289,890
Accumulated other comprehensive income (loss), net of income taxes		(44,044	)		(46,057	)
Retained earnings		386,003			405,884
Total PNMR common stockholders’ equity		1,632,207			1,649,717
Non-controlling interest in Valencia		89,330			89,359
Total equity		1,821,537			1,839,076

	$	5,460,390		$	5,359,921

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

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Cash Flows From Operating Activities:
Net earnings (loss)	$	(5,214	)	$	92,260
Adjustments to reconcile net earnings (loss) to net cash flows from operating activities:
Depreciation and amortization		44,318			42,305
PVNGS firm sales contract revenue		(14,329	)		(13,964	)
Bad debt expense		6,397			14,908
Deferred income taxes (benefit)		(4,334	)		(89,714	)
Equity in net (earnings) loss of Optim Energy		4,352			(1,395	)
Net unrealized losses on derivatives		33,355			6,955
Realized (gains) losses on investments held by NDT		(1,743	)		4,382
Gain on sale of PNM Gas		-			(101,369	)
Gain on reacquired debt		-			(7,467	)
Stock based compensation expense		1,427			1,070
Other, net		(807	)		333
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues		16,113			4,423
Materials, supplies, and fuel stock		98			2,098
Other current assets		(70,817	)		(1,521	)
Other assets		(4,594	)		1,386
Accounts payable		(8,078	)		(79,020	)
Accrued interest and taxes		22,950			139,815
Other current liabilities		(21,680	)		(26,823	)
Other liabilities		(10,670	)		(3,950	)
Net cash flows from operating activities		(13,256	)		(15,288	)

Cash Flows From Investing Activities:
Utility plant additions		(67,542	)		(80,850	)
Proceeds from sales of investments held by NDT		20,699			44,391
Purchases of investments held by NDT		(21,614	)		(44,724	)
Proceeds from sale of PNM Gas		-			640,620
Transaction costs for sale of PNM Gas		-			(10,604	)
Return of principal on PVNGS lessor notes		14,216			11,458
Other, net		165			416
Net cash flows from investing activities		(54,076	)		560,707

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

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net		89,973			(599,067	)
Long-term borrowings		-			309,242
Repayment of long-term debt		-			(314,079	)
Issuance of common stock		-			620
Proceeds from stock option exercise		483			-
Purchase of common stock to satisfy stock awards		(1,446	)		(803	)
Excess tax (shortfall) from stock-based payment arrangements		(106	)		(519	)
Dividends paid		(11,564	)		(11,546	)
Equity transactions with Valencia’s owner		(3,132	)		-
Payments received on PVNGS firm-sales contracts		7,593			7,634
Debt issuance costs and other		(124	)		(7,075	)
Net cash flows from financing activities		81,677			(615,593	)

Change in Cash and Cash Equivalents		14,345			(70,174	)
Cash and Cash Equivalents at Beginning of Period		14,641			140,644
Cash and Cash Equivalents at End of Period	$	28,986		$	70,470

Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	5,349		$	19,533
Income taxes paid (refunded), net	$	(2,020	)	$	(1,777	)

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

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PNMR COMMON STOCKHOLDERS’ EQUITY

(Unaudited)

						Accumulated						Total PNMR
	Common Stock					Other						Common
	Number of		Aggregate			Comprehensive			Retained			Stockholders’
	Shares		Value			Income (Loss)			Earnings			Equity
			(Dollars in thousands)

Balance at December 31, 2009		86,673,174	$	1,289,890		$	(46,057	)	$	405,884		$	1,649,717
Purchase of common stock to satisfy stock awards		-		(963	)		-			-			(963	)
Tax shortfall from stock-based compensation arrangements		-		(106	)		-			-			(106	)
Stock based compensation expense		-		1,427			-			-			1,427
Net earnings (loss) attributable to PNMR		-		-			-			(8,449	)		(8,449	)
Total other comprehensive income		-		-			2,013			-			2,013
Dividends declared on common stock		-		-			-			(11,432	)		(11,432	)
Balance at March 31, 2010		86,673,174	$	1,290,248		$	(44,044	)	$	386,003		$	1,632,207

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

PNM RESOURCES, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)

Net Earnings (Loss)	$	(5,214	)	$	92,260

Other Comprehensive Income (Loss):

Unrealized Gain on Investment Securities :
Unrealized holding gains arising during
the period, net of income tax (expense)
of $(1,222) and $(353)		1,865			538
Reclassification adjustment for (gains) included in
net earnings (loss), net of income tax expense
of $610 and $292		(931	)		(446	)

Pension liability adjustment, net of income tax benefit
of $147 and $38,671		(223	)		(59,008	)

Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense)
of $(5,056) and $(10,794)		7,617			15,137
Reclassification adjustment for (gains) losses included in
net earnings (loss), net of income tax expense
of $4,192 and $6,101		(6,315	)		(9,090	)

Total Other Comprehensive Income (Loss)		2,013			(52,869	)

Comprehensive Income (Loss)		(3,201	)		39,391

Comprehensive Income Attributable to Valencia Non-controlling Interest		(3,103	)		(2,579	)

Preferred Stock Dividend Requirements of Subsidiary		(132	)		(132	)

Comprehensive Income (Loss) Attributable to PNMR	$	(6,436	)	$	36,680

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

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 March 31,
	2010			2009
	(In thousands)

Electric Operating Revenues	$	230,536		$	231,955

Operating Expenses:
Cost of energy		86,434			101,533
Administrative and general		37,686			29,690
Energy production costs		53,885			50,944
Depreciation and amortization		22,852			22,428
Transmission and distribution costs		9,308			9,073
Taxes other than income taxes		7,914			7,801
Total operating expenses		218,079			221,469
Operating income		12,457			10,486

Other Income and Deductions:
Interest income		4,935			5,961
Gains (losses) on investments held by NDT		1,743			(4,382	)
Other income		10,037			316
Other deductions		(623	)		(866	)
Net other income (deductions)		16,092			1,029

Interest Charges		18,077			17,207

Earnings (Loss) before Income Taxes		10,472			(5,692	)

Income Taxes (Benefit)		2,921			(3,348	)

Earnings (Loss) from Continuing Operations		7,551			(2,344	)

Earnings from Discontinued Operations, net of Income
Taxes of $0 and $40,027		-			75,853

Net Earnings		7,551			73,509

Earnings Attributable to Valencia Non-controlling Interest		(3,103	)		(2,579	)

Net Earnings Attributable to PNM		4,448			70,930

Preferred Stock Dividends Requirements		(132	)		(132	)

Net Earnings Available for PNM Common Stock	$	4,316		$	70,798

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

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,		December 31,
	2010		2009
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	10,546	$	1,373
Special deposits		31,912		2
Accounts receivable, net of allowance for uncollectible accounts of $1,483 and $1,483		61,236		70,515
Unbilled revenues		32,562		38,067
Other receivables		76,060		74,120
Affiliate accounts receivable		24		33
Materials, supplies, and fuel stock		47,497		47,789
Regulatory assets		18,976		7,476
Commodity derivative instruments		24,968		24,498
Income taxes receivable		56,926		59,299
Other current assets		47,787		40,197

Total current assets		408,494		363,369

Other Property and Investments:
Investment in PVNGS lessor notes		121,796		137,511
Investments held by NDT		141,237		137,032
Other investments		7,515		7,473
Non-utility property		976		976

Total other property and investments		271,524		282,992

Utility Plant:
Plant in service and plant held for future use		3,711,182		3,677,974
Less accumulated depreciation and amortization		1,270,202		1,260,903
		2,440,980		2,417,071
Construction work in progress		152,144		159,793
Nuclear fuel, net of accumulated amortization of $23,830 and $19,456		75,473		69,337

Net utility plant		2,668,597		2,646,201

Deferred Charges and Other Assets:
Regulatory assets		372,112		375,131
Goodwill		51,632		51,632
Other deferred charges		71,199		55,841

Total deferred charges and other assets		494,943		482,604
	$	3,843,558	$	3,775,166

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

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
	2010			2009
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	178,000		$	118,000
Accounts payable		66,491			57,473
Affiliate accounts payable		14,183			13,481
Accrued interest and taxes		39,265			24,124
Regulatory liabilities		1,701			908
Commodity derivative instruments		6,393			1,509
Other current liabilities		102,125			126,273

Total current liabilities		408,158			341,768

Long-term Debt		1,055,736			1,055,733

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		366,218			364,498
Accumulated deferred investment tax credits		19,911			20,518
Regulatory liabilities		313,079			316,215
Asset retirement obligations		71,536			70,099
Accrued pension liability and postretirement benefit cost		259,933			265,791
Commodity derivative instruments		1,199			556
Other deferred credits		93,187			90,425

Total deferred credits and liabilities		1,125,063			1,128,102

Total liabilities		2,588,957			2,525,603

Commitments and Contingencies (See Note 9)

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)		1,018,776			1,018,776
Accumulated other comprehensive income (loss), net of income taxes		(51,056	)		(51,807	)
Retained earnings		186,022			181,706
Total PNM common stockholder’s equity		1,153,742			1,148,675
Non-controlling interest in Valencia		89,330			89,359
Total equity		1,243,072			1,238,034

	$	3,843,558		$	3,775,166

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

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	7,551		$	73,509
Adjustments to reconcile net earnings to net cash flows from operating activities:
Depreciation and amortization		28,010			25,934
PVNGS firm sales contract revenue		(14,329	)		(13,964	)
Deferred income taxes (benefit)		620			(91,481	)
Net unrealized losses on derivatives		5,289			5,887
Realized (gains) losses on investments held by NDT		(1,743	)		4,382
Gain on sale of PNM Gas		-			(101,369	)
Other, net		(203	)		262
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues		14,181			5,463
Materials, supplies, and fuel stock		292			1,698
Other current assets		(48,578	)		9,009
Other assets		2,219			4,504
Accounts payable		9,018			(32,116	)
Accrued interest and taxes		17,514			136,943
Other current liabilities		(16,083	)		(28,205	)
Other liabilities		(10,142	)		(2,890	)
Net cash flows from operating activities		(6,384	)		(2,434	)

Cash Flows From Investing Activities:
Utility plant additions		(62,025	)		(71,123	)
Proceeds from sales of NDT investments		20,699			44,391
Purchases of NDT investments		(21,614	)		(44,724	)
Proceeds from sale of PNM Gas		-			640,620
Transaction cost for sale of PNM Gas		-			(10,604	)
Return of principal on PVNGS lessor notes		14,216			13,339
Other, net		(48	)		101
Net cash flows from investing activities		(48,772	)		572,000

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

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Cash Flows From Financing Activities:
Short-term borrowings (repayments), net		60,000			(340,000	)
Payments received on PVNGS firm-sales contracts		7,593			7,634
Equity transactions with Valencia’s owner		(3,132	)		-
Dividends paid		(132	)		(220,132	)
Net cash flows from financing activities		64,329			(552,498	)

Change in Cash and Cash Equivalents		9,173			17,068
Cash and Cash Equivalents at Beginning of Period		1,373			46,622
Cash and Cash Equivalents at End of Period	$	10,546		$	63,690

Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	3,773		$	4,755
Income taxes paid (refunded), net	$	-		$	-

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

PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PNM COMMON STOCKHOLDER’S EQUITY

(Unaudited)

					Accumulated					Total PNM
	Common Stock				Other					Common
	Number of		Aggregate		Comprehensive			Retained		Stockholder’s
	Shares		Value		Income (Loss)			Earnings		Equity
			(Dollars in thousands)

Balance at December 31, 2009		39,117,799	$	1,018,776	$	(51,807	)	$	181,706	$	1,148,675
Net earnings attributable to PNM		-		-		-			4,448		4,448
Total other comprehensive income		-		-		751			-		751
Dividends on preferred stock		-		-		-			(132)		(132)
Balance at March 31, 2010		39,117,799	$	1,018,776	$	(51,056	)	$	186,022	$	1,153,742

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

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 March 31,
	2010			2009
	(In thousands)

Net Earnings	$	7,551		$	73,509

Other Comprehensive Income (Loss):

Unrealized Gain on Investment Securities :
Unrealized holding gains arising during
the period, net of income tax (expense)
of $(1,222) and $(353)		1,865			538
Reclassification adjustment for (gains) included in
net earnings, net of income tax expense
of $610 and $292		(931	)		(446	)

Pension liability adjustment, net of income tax benefit
of $147 and $38,671		(223	)		(59,008	)

Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax (expense)
of $(2,696) and $(7,459)		4,114			11,381
Reclassification adjustment for (gains) included in
net earnings, net of income tax expense
of $2,670 and $3,849		(4,074	)		(5,872	)

Total Other Comprehensive Income (Loss)		751			(53,407	)

Comprehensive Income		8,302			20,102

Comprehensive Income Attributable to Valencia Non-controlling Interest		(3,103	)		(2,579	)

Comprehensive Income Attributable to PNM	$	5,199		$	17,523

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

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Electric Operating Revenues:
Non-affiliates	$	38,591		$	31,922
Affiliate		9,586			9,303
Total electric operating revenues		48,177			41,225

Operating Expenses:
Cost of energy		9,051			8,595
Administrative and general		9,494			8,329
Depreciation and amortization		10,095			8,598
Transmission and distribution costs		4,581			4,941
Taxes other than income taxes		4,714			4,677
Total operating expenses		37,935			35,140
Operating income		10,242			6,085

Other Income and Deductions:
Other income		364			417
Other deductions		(18	)		(25	)
Net other income (deductions)		346			392

Interest Charges		7,869			4,095

Earnings Before Income Taxes		2,719			2,382

Income Taxes		1,075			961

Net Earnings	$	1,644		$	1,421

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

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,		December 31,
	2010		2009
	(In thousands)
ASSETS
Current Assets:
Cash and cash equivalents	$	71	$	138
Special deposits		50		50
Accounts receivable		13,264		11,773
Unbilled revenues		5,199		7,239
Other receivables		848		579
Affiliate accounts receivable		4,730		5,151
Materials and supplies		2,818		2,591
Income taxes receivable		7,088		10,762
Other current assets		448		1,012

Total current assets		34,516		39,295

Other Property and Investments:
Other investments		270		270
Non-utility property		2,111		2,111

Total other property and investments		2,381		2,381

Utility Plant:
Plant in service and plant held for future use		871,605		864,260
Less accumulated depreciation and amortization		296,304		292,608
		575,301		571,652
Construction work in progress		4,455		9,832

Net utility plant		579,756		581,484

Deferred Charges and Other Assets:
Regulatory assets		152,944		149,005
Goodwill		226,665		226,665
Other deferred charges		10,485		10,225

Total deferred charges and other assets		390,094		385,895

	$	1,006,747	$	1,009,055

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

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	March 31,			December 31,
	2010			2009
	(In thousands, except share information)
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt – affiliate	$	17,500		$	23,500
Accounts payable		2,623			6,243
Affiliate accounts payable		1,109			2,281
Accrued interest and taxes		17,878			16,505
Other current liabilities		2,515			2,194

Total current liabilities		41,625			50,723

Long-term Debt		309,868			309,712

Deferred Credits and Other Liabilities:
Accumulated deferred income taxes		135,032			136,944
Regulatory liabilities		41,425			34,109
Asset retirement obligations		788			772
Accrued pension liability and postretirement benefit cost		15,748			16,132
Other deferred credits		9,272			8,872

Total deferred credits and other liabilities		202,265			196,829

Total liabilities		553,758			557,264

Commitments and Contingencies (See Note 9)

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		443,187			443,187
Accumulated other comprehensive income (loss), net of income taxes		(520	)		(74	)
Retained earnings		10,258			8,614

Total common stockholder’s equity		452,989			451,791

	$	1,006,747		$	1,009,055

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

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Cash Flows From Operating Activities:
Net earnings	$	1,644		$	1,421
Adjustments to reconcile net earnings to
net cash flows from operating activities:
Depreciation and amortization		11,101			10,317
Deferred income taxes (benefit)		(1,665	)		(789	)
Other, net		10			13
Changes in certain assets and liabilities:
Accounts receivable and unbilled revenues		549			2,065
Materials and supplies		(227	)		(93	)
Other current assets		296			(144	)
Other assets		(856	)		(11	)
Accounts payable		(3,620	)		(7,996	)
Accrued interest and taxes		5,047			(8,230	)
Other current liabilities		(429	)		2,209
Other liabilities		(585	)		(796	)
Net cash flows from operating activities		11,265			(2,034	)

Cash Flows From Investing Activities:
Utility plant additions		(5,207	)		(8,052	)
Net cash flows from investing activities		(5,207	)		(8,052	)

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

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31,
	2010			2009
	(In thousands)
Cash Flow From Financing Activities:
Short-term borrowings (repayments), net		-			(150,000	)
Short-term borrowings (repayments), net – affiliate		(6,000	)		24,700
Long-term borrowings		-			309,242
Repayment of long-term debt		-			(167,690	)
Debt issuance costs and other		(125	)		(6,231	)
Net cash flows from financing activities		(6,125	)		10,021

Change in Cash and Cash Equivalents		(67	)		(65	)
Cash and Cash Equivalents at Beginning of Period		138			124
Cash and Cash Equivalents at End of Period	$	71		$	59

Supplemental Cash Flow Disclosures:
Interest paid, net of capitalized interest	$	865		$	8,650
Income taxes paid (refunded), net	$	(860	)	$	(935	)

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

TEXAS-NEW MEXICO POWER COMPANY AND SUBSIDIARIES

A WHOLLY OWNED SUBSIDIARY OF PNM RESOURCES, INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDER’S EQUITY

(Unaudited)

							Accumulated					Total
	Common Stock						Other					Common
	Number of		Aggregate		Paid-in		Comprehensive			Retained		Stockholder’s
	Shares		Value		Capital		Income (Loss)			Earnings		Equity
			(Dollars in thousands)

Balance at December 31, 2009		6,358	$	64	$	443,187	$	(74	)	$	8,614	$	451,791
Net earnings		-		-		-		-			1,644		1,644
Total other comprehensive income (loss)		-		-		-		(446	)		-		(446	)
Balance at March 31, 2010		6,358	$	64	$	443,187	$	(520	)	$	10,258	$	452,989

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

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 March 31,
	2010			2009
	(In thousands)

Net Earnings	$	1,644		$	1,421

Other Comprehensive Income (Loss):

Fair Value Adjustment for Designated Cash Flow Hedges:
Change in fair market value, net of income tax
benefit of $350 and $300		(631	)		(541	)
Reclassification adjustment for losses included in
net earnings, net of income tax (benefit)
of $(102) and $0		185			-

Total Other Comprehensive Income (Loss)		(446	)		(541	)

Comprehensive Income	$	1,198		$	880

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

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 March 31, 2010 and December 31, 2009, and the consolidated results of operations, comprehensive income, and cash flows for the three months ended March 31, 2010 and 2009. The preparation of financial statements in conformity with generally accepted accounting principles in the United States 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. The results of operations presented in the accompanying Condensed Consolidated Financial Statements are not necessarily representative of operations for an entire year.

These Condensed Consolidated Financial Statements are unaudited, and 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 2009 Annual Reports on Form 10-K.

The Notes to Condensed Consolidated Financial Statements include disclosures for PNMR, PNM, and TNMP. For discussion purposes, this report will use the term “Company” when discussing matters of common applicability to PNMR, PNM, and TNMP. Discussions regarding only PNMR, PNM, or TNMP will be indicated as such. Certain amounts in the 2009 Condensed Consolidated Financial Statements and Notes thereto have been reclassified to conform to the 2010 financial statement presentation.

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. PNMR’s primary subsidiaries are PNM, TNMP, and First Choice. PNM consolidates the PVNGS Capital Trust and Valencia. PNMR shared services’ administrative and general expenses, which represent costs that are primarily driven by corporate level activities, are allocated to the business segments. Other significant intercompany transactions between PNMR, PNM, and TNMP include energy purchases and sales, transmission and distribution services, lease payments, and dividends paid on common stock. All intercompany transactions and balances have been eliminated. See Note 12.

Restatement

As discussed in Note 12 of Notes to Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K, the actuarial determination of the PBO for the PNM pension plan at December 31, 2009 revealed that there had been an increase in the PBO of $9.6 million due to the retirement of employees transferred to NMGC following the sale of PNM Gas in January 2009. This increase was expensed, similar to a plan curtailment, as required by GAAP and reduced the gain recognized on the sale. The expense for the PBO increase is reflected through a retroactive adjustment of the March 31, 2009 quarter for PNMR and PNM. The retroactive adjustment is part of discontinued operations for PNMR and PNM and does not impact earnings from continuing operations or earnings

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)

per share from continuing operations. The retroactive adjustment had the following impact on the March 31, 2009 amounts:

	Quarter Ended March 31, 2009
	As Originally
	Reported		As Restated
	(In thousands, except per share amounts)

PNMR
Net earnings (loss)	$	98,082	$	92,260
Net earnings (loss) attributable to PNMR		95,371		89,549
Net earnings (loss) attributable to PNMR per common share:
Basic		1.04		0.98
Diluted		1.04		0.98

PNM
Net earnings		79,331		73,509
Net earnings attributable to PNM		76,752		70,930

(2)	Disposition

PNM Gas Sale

On January 12, 2008, PNM reached a definitive agreement to sell its natural gas operations, which comprised the PNM Gas segment, to NMGC, a subsidiary of Continental, for $620.0 million in cash, subject to adjustment based on the actual level of working capital at closing. PNM received an additional $32.9 million related to working capital true-ups, including $20.6 million received at closing. In a separate transaction conditioned upon the sale of the natural gas operations, PNMR proposed to acquire CRHC, Continental's regulated Texas electric transmission and distribution business, for $202.5 million in cash. On July 22, 2008, PNMR and Continental agreed to terminate the agreement for the acquisition of CRHC. Under the termination agreement, Continental agreed to pay PNMR $15.0 million upon the closing of the PNM Gas transaction. PNM completed the sale of PNM Gas on January 30, 2009 and recognized a gain of $67.1 million, after income taxes of $34.3 million in 2009, which is included in discontinued operations. This gain reflects the reduction for the increase in the PBO of the PNM pension plan related to the retirement of employees transferred to NMGC. See Note 1. PNMR recognized an additional pre-tax gain of $15.0 million ($9.1 million after income taxes) due to the CRHC termination payment, which is included in other income. In connection with the sale, PNM retained obligations under the frozen PNM pension and executive retirement plans for employees transferred to NMGC. PNM had a regulatory asset related to these plans, which was removed from regulatory assets and transferred to AOCI. The after-tax charge to AOCI was $59.0 million. PNM also retained obligations for certain contingent liabilities that existed at the date of sale.

PNM used proceeds from the sale to retire short-term debt and paid a dividend of $220.0 million to PNMR. PNMR used the dividend from PNM and the $15.0 million from Continental to retire debt. There were no material prior relationships between the PNMR and Continental parties other than in respect of the transactions described herein. See Note 14 for financial information concerning PNM Gas, which is classified as discontinued operations in the accompanying financial statements.

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)

(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 Electric

PNM Electric includes the retail electric utility operations of PNM that are subject to traditional rate regulation by the NMPRC. PNM Electric provides integrated electricity services that include the generation, transmission and distribution of electricity for retail electric customers in New Mexico as well as the sale of transmission to third parties. PNM Electric also includes the generation and sale of electricity into the wholesale market. This includes optimization of PNM’s jurisdictional assets as well as the capacity excluded from retail rates. FERC has jurisdiction over wholesale rates.

TNMP Electric

TNMP Electric is a regulated utility operating in Texas. TNMP’s operations are subject to traditional rate regulation by the PUCT. TNMP provides regulated transmission and distribution services in Texas under the TECA.

PNM Gas

PNM Gas distributed natural gas to most of the major communities in New Mexico, subject to traditional rate regulation by the NMPRC. The customer base of PNM Gas included both sales-service customers and transportation-service customers. PNM Gas purchased natural gas in the open market and sold it at cost to its sales-service customers. As a result, increases or decreases in gas revenues resulting from gas price fluctuations did not impact gross margin or earnings. As described in Note 2, PNM completed the sale of its gas operations on January 30, 2009. PNM Gas is reported as discontinued operations in the accompanying financial statements and is not included in the segment information presented below. Financial information regarding PNM Gas is presented in Note 14.

First Choice

First Choice is a certified retail electric provider operating in Texas that primarily serves residential, small commercial, and governmental customers. Although First Choice is regulated in certain respects by the PUCT, it is not subject to traditional rate of return regulation.

Optim Energy

Optim Energy is treated as a separate segment for PNMR. PNMR’s investment in Optim Energy is held in the Corporate and Other segment and is accounted for using the equity method of accounting. Optim Energy’s revenues and expenses are not included in PNMR’s consolidated revenues and expenses or the following tables. See Note 11.

Corporate and Other

PNMR Services Company is included in the Corporate and Other segment.

The following tables present summarized financial information for PNMR by reportable segment. Excluding PNM Gas, which is presented as discontinued operations, PNM has only one operating segment. TNMP operates in only one reportable segment. Therefore, tabular segment information is not presented for PNM and TNMP.

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 SEGMENT INFORMATION

	PNM			TNMP			First			Corporate
Three Months Ended March 31, 2010	Electric			Electric			Choice			and Other			Consolidated
							(In thousands)
Operating revenues	$	230,536		$	38,591		$	114,390		$	(60	)	$	383,457
Intersegment revenues		-			9,586			-			(9,586	)		-
Total revenues		230,536			48,177			114,390			(9,646	)		383,457
Cost of energy		86,434			9,051			104,990			(9,587	)		190,888
Gross margin		144,102			39,126			9,400			(59	)		192,569
Other operating expenses		108,793			18,789			20,448			(3,283	)		144,747
Depreciation and amortization		22,852			10,095			263			4,069			37,279
Operating income (loss)		12,457			10,242			(11,311	)		(845	)		10,543

Interest income		4,935			-			2			90			5,027
Equity in net earnings (loss) of Optim Energy		-			-			-			(4,352	)		(4,352	)
Other income (deductions)		11,157			346			(8	)		(1,456	)		10,039
Interest charges		(18,077	)		(7,869	)		(311	)		(5,153	)		(31,410	)

Segment earnings (loss) before income taxes		10,472			2,719			(11,628	)		(11,716	)		(10,153	)

Income taxes (benefit)		2,921			1,075			(4,175	)		(4,760	)		(4,939	)

Segment earnings (loss) from continuing operations		7,551			1,644			(7,453	)		(6,956	)		(5,214	)

Valencia non-controlling interest		(3,103	)		-			-			-			(3,103	)
Subsidiary preferred stock dividends		(132	)		-			-			-			(132	)

Segment earnings (loss) from continuing operations attributable to PNMR	$	4,316		$	1,644		$	(7,453	)	$	(6,956	)	$	(8,449	)

At March 31, 2010:
Total Assets	$	3,843,558		$	1,006,747		$	232,864		$	377,221		$	5,460,390
Goodwill	$	51,632		$	226,665		$	43,013		$	-		$	321,310

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			First			Corporate
Three Months Ended March 31, 2009	Electric			Electric			Choice			and Other			Consolidated
							(In thousands)
Operating revenues	$	231,944		$	31,922		$	122,174		$	(175	)	$	385,865
Intersegment revenues		11			9,303			-			(9,314	)		-
Total revenues		231,955			41,225			122,174			(9,489	)		385,865
Cost of energy		101,533			8,595			80,423			(9,303	)		181,248
Gross margin		130,422			32,630			41,751			(186	)		204,617
Other operating expenses		97,508			17,947			29,332			(6,144	)		138,643
Depreciation and amortization		22,428			8,598			518			4,527			36,071
Operating income		10,486			6,085			11,901			1,431			29,903

Interest income		5,961			-			35			(773	)		5,223
Equity in net earnings of Optim Energy		-			-			-			1,395			1,395
Other income (deductions)		(4,932	)		392			-			20,962			16,422
Interest charges		(17,207	)		(4,095	)		(999	)		(6,648	)		(28,949	)

Segment earnings (loss) before income taxes		(5,692	)		2,382			10,937			16,367			23,994

Income taxes (benefit)		(3,348	)		961			3,899			6,075			7,587

Segment earnings (loss) from continuing operations		(2,344	)		1,421			7,038			10,292			16,407

Valencia non-controlling interest		(2,579	)		-			-			-			(2,579	)
Subsidiary preferred stock dividends		(132	)		-			-			-			(132	)

Segment earnings (loss) from continuing operations attributable to PNMR	$	(5,055	)	$	1,421		$	7,038		$	10,292		$	13,696

At March 31, 2009:
Total Assets	$	3,676,562		$	971,998		$	245,885		$	383,117		$	5,277,562
Goodwill	$	51,632		$	226,665		$	43,013		$	-		$	321,310

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)

(4)	Energy Related Derivative Contracts and Fair Value Disclosures

Energy Related Derivative Contracts

The Company is exposed to certain risks relating to its ongoing business operations. 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 or fuel used to generate electricity, or to manage anticipated generation capacity in excess of forecasted demand from existing customers. Substantially all of the Company’s energy related derivative contracts are entered into to manage commodity risk and the Company does not currently engage in speculative trading.

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. The Company 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 risk of market fluctuations in wholesale portfolios. The Company monitors the market risk of its commodity contracts using VaR and GEaR calculations to maintain total exposure within management-prescribed limits.

PNM is required to meet the demand and energy needs of its retail and wholesale customers. For PNM’s share of PVNGS Unit 3 and the requirements of retail customers not covered under PNM’s FPPAC, PNM is exposed to market risk. 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 would be exposed to market risk if its generation capabilities were to be disrupted or if its retail load requirements were to be greater than anticipated. If all or a portion of the net open contract position were required to be covered as a result of the aforementioned unexpected situations, commitments would have to be met through market purchases. As discussed in Note 10, on April 20, 2010, PNM received NMPRC approval of a hedging plan to manage fuel and purchased power costs related to those customers under the FPPAC.

First Choice is responsible for energy supply related to the sale of electricity to retail customers in Texas. TECA contains no provisions for the specific recovery of fuel and purchased power costs. The rates charged to First Choice customers are negotiated with each customer. As a result, changes in purchased power costs can affect First Choice’s operating results with respect to margins and changes in retail customer load requirements. First Choice is exposed to market risk to the extent that it has not hedged fixed price load commitments or to the degree that market price movements affect customer retention, customer additions or customer attrition. Additionally, volumetric fluctuations in First Choice retail load requirements due to weather or other conditions may subject First Choice to market risk. First Choice’s strategy is to minimize its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins.

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. Energy contracts that meet the definition of a derivative under GAAP and do not qualify for the normal sales and purchases exception are recorded on the balance sheet at fair value at each period end. The changes in fair value are recognized in earnings unless specific hedge accounting criteria are met. Derivatives that meet the normal sales and purchases exception are not marked to market but rather recorded in results of operations when the underlying transactions settle.

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 derivative transactions meeting the definition of a cash flow hedge, the Company documents the relationships between the hedging instruments and the items being hedged. This documentation includes the strategy that supports executing the specific transaction and the methods utilized to assess the effectiveness of the hedges. Changes in the fair value of contracts qualifying for cash flow hedge accounting are included in AOCI to the extent effective. Ineffectiveness gains and losses were immaterial for all periods presented. The amounts shown as current assets and current liabilities relate to contracts that will be settled in the next twelve months. Gains or losses related to cash flow hedge instruments are reclassified from AOCI when the hedged transaction settles and impacts earnings. Based on market prices at March 31, 2010, after-tax gains of $11.8 million for PNMR and $12.8 million for PNM would be reclassified from AOCI into earnings during the next twelve months. However, the actual amount reclassified into earnings will vary due to future changes in market prices. As of March 31, 2010, the maximum length of time over which the Company is hedging its exposure to the variability in future cash flows is through December 2010.

The contracts recorded at fair value that do not qualify or are not designated for cash flow hedge accounting are classified as either economic hedges or trading transactions. 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. Trading transactions include speculative transactions, which the Company ceased in 2008.

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 the Company’s own credit standing. The Company regularly assesses the validity and availability of pricing data for its derivative transactions. Although management uses its best judgment in estimating the fair value of these instruments, there are inherent limitations in any estimation technique.

At March 31, 2010, amounts recognized for the right to reclaim cash collateral are $4.3 million for PNMR and $3.8 million for PNM. PNMR and PNM had no obligations to return cash collateral at March 31, 2010.

The following tables do not include activity related to PNM Gas. See Note 14.

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)

Commodity Derivatives

Commodity derivative instruments are summarized as follows:

													Qualified Cash
	Economic Hedges						Trading Transactions						Flow Hedges
	March 31, 2010			December 31, 2009			March 31, 2010			December 31, 2009			March 31, 2010		December 31, 2009
				(In thousands)
PNMR
Current assets	$	24,219		$	15,728		$	16,274		$	13,889		$	21,290	$	21,002
Deferred charges		3,779			2,413			-			-			-		-
		27,998			18,141			16,274			13,889			21,290		21,002

Current liabilities		(44,618	)		(11,375	)		(15,326	)		(12,650	)		-		-
Long-term liabilities		(12,133	)		(4,549	)		-			-			-		-
		(56,751	)		(15,924	)		(15,326	)		(12,650	)		-		-

Net	$	(28,753	)	$	2,217		$	948		$	1,239		$	21,290	$	21,002

PNM
Current assets	$	3,678		$	3,496		$	-		$	-		$	21,290	$	21,002
Deferred charges		-			-			-			-			-		-
		3,678			3,496			-			-			21,290		21,002

Current liabilities		(6,393	)		(1,509	)		-			-			-		-
Long-term liabilities		(1,199	)		(556	)		-			-			-		-
		(7,592	)		(2,065	)		-			-			-		-
Net	$	(3,914	)	$	1,431		$	-		$	-		$	21,290	$	21,002

First Choice decided to end speculative trading in 2008 and flattened remaining speculative positions. The PNMR trading transactions column of the above table includes all balances related to the remaining flattened speculative positions of First Choice. No significant additional costs are expected related to speculative trading.

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 table presents the effect of commodity derivative instruments on earnings and OCI, excluding income tax effects. For cash flow hedges, including those de-designated, the earnings impact reflects the reclassification from AOCI when the hedged transactions settle.

	Economic Hedges						Trading Transactions					Qualified Cash Flow Hedges
	Three Months Ended March 31,						Three Months Ended March 31,					Three Months Ended March 31,
	2010			2009			2010		2009			2010			2009
							(In thousands)
PNMR
Electric operating revenues	$	(1,886	)	$	3,804		$	3	$	(5	)	$	6,749		$	9,676
Cost of energy		(31,949	)		(14,065	)		-		-			(477	)		(2,161	)
Total gain (loss)	$	(33,835	)	$	(10,261	)	$	3	$	(5	)	$	6,272		$	7,515

Recognized in OCI												$	765		$	(1,232	)

PNM
Electric operating revenues	$	(1,886	)	$	3,804		$	-	$	61		$	6,749		$	9,676
Cost of energy		(3,625	)		(11,783	)		-		-			55			46
Total gain (loss)	$	(5,511	)	$	(7,979	)	$	-	$	61		$	6,804		$	9,722

Recognized in OCI												$	233		$	9,119

Commodity contract volume positions are presented in Decatherms 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:

	Decatherms							MWh
	Economic Hedges		Trading Transactions			Qualified Cash Flow Hedges		Economic Hedges		Trading Transactions		Qualified Cash Flow Hedges

March 31, 2010
PNMR		20,192,500		(1,480,137	)		-		2,056,226		-		(594,090	)
PNM		4,580,000		-			-		321,275		-		(594,090	)

December 31, 2009
PNMR		17,852,500		(1,963,293	)		-		1,658,101		-		(788,400	)
PNM		6,087,500		-			-		468,525		-		(788,400	)

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.

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 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 the existing contracts and does not reflect letters of credit under the Company’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 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)
March 31, 2010
PNMR	$	26,059	$	-	$	18,856
PNM	$	303	$	-	$	276

December 31, 2009
PNMR	$	17,124	$	1,000	$	14,104
PNM	$	1,211	$	1,000	$	37

Sale of Power from PVNGS Unit 3

In April 2008, PNM entered into three separate contracts for the sale of capacity and energy related to its entire ownership interest in PVNGS Unit 3, which is 135 MW. Under two of the contracts, PNM sells 90 MW of firm capacity and energy. Under the remaining contract, PNM sells 45 MW of unit contingent capacity and energy. The term of the contracts is May 1, 2008 through December 31, 2010. Under the two firm contracts, the two buyers made prepayments of $40.6 million and $30.0 million. These amounts were recorded as deferred revenue and are being amortized over the life of the contracts. At March 31, 2010 and December 31, 2009, $21.1 million and $29.5 million were included in other current liabilities related to these contracts. The prepayments received under the firm contracts, as well as required subsequent monthly payments on them, are shown as a financing activity in the Condensed Consolidated Statement of Cash Flows. The firm contracts are considered energy derivatives. The firm contracts are accounted for as cash flow hedges and changes in fair value are included in AOCI. The contingent contract is accounted for as a normal sale.

Non-Derivative Financial Instruments

The carrying amounts reflected on the Condensed Consolidated Balance Sheets approximate fair value for cash, temporary investments, 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 trust for its share of decommissioning costs of PVNGS. The trust holds equity and fixed income securities. The fair value and gross unrealized gains of investments in available for sale securities are presented in the following table. PNMR and PNM do not have any unrealized losses on available for sale securities.

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)

	March 31, 2010				December 31, 2009
	Unrealized Gains		Fair Value		Unrealized Gains		Fair Value
			(In thousands)
Equity securities:
Domestic value	$	3,891	$	22,939	$	1,684	$	21,458
Domestic growth		10,957		40,541		8,901		38,132
International and other		2,164		9,845		1,558		9,985
Fixed income securities:
Municipals		1,713		37,224		1,715		36,901
U.S. Government		120		20,448		25		20,451
Corporate and other		511		8,333		309		8,006
Cash investments		-		1,907		-		2,099
	$	19,356	$	141,237	$	14,192	$	137,032

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.

	Three Months Ended March 31, 2010
	(In thousands)


Proceeds from sales	$	20,699
Gross realized gains	$	1,905
Gross realized (losses)	$	(1,362	)

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, including the EIP lessor note.

The Company has no available-for-sale or held-to-maturity securities for which carrying value exceeds fair value. There are no impairments considered to be “other than temporary” that are included in AOCI and not recognized in earnings.

At March 31, 2010, 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	$	548	$	35	$	35
After 1 year through 5 years		19,338		179,457		164,891
After 5 years through 10 years		8,109		4,473		-
Over 10 years		38,010		-		-
	$	66,005	$	183,965	$	164,926

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 amount and fair value of other non-derivative financial instruments (including current maturities) are:

	March 31, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In thousands)
PNMR
Long-term debt	$	1,567,491	$	1,643,491	$	1,567,331	$	1,627,986
Investment in PVNGS lessor notes	$	152,805	$	157,137	$	159,936	$	169,863
Other investments	$	24,645	$	29,645	$	25,528	$	34,078

PNM
Long-term debt	$	1,055,736	$	1,057,525	$	1,055,733	$	1,044,516
Investment in PVNGS lessor notes	$	152,805	$	157,137	$	159,936	$	169,863
Other investments	$	7,515	$	8,597	$	7,473	$	8,457

TNMP
Long-term debt	$	309,868	$	375,345	$	309,712	$	368,350
Other investments	$	270	$	270	$	270	$	270

The fair value of long-term debt shown above was primarily determined using quoted market values, as were certain items included in other investments. To the extent market values were not available, fair value was determined by discounting the cash flows for the instrument using quoted interest rates for comparable instruments.

Other Fair Value Disclosures

The Company determines the fair values of its derivative and other 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.

For NDT investments, 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. Fair values of Level 3 commodity derivatives are determined in a manner similar to those in Level 2, but are at a lower level in the hierarchy due to low transaction volume or market illiquidity that significantly limit the availability of observable market data.

Derivatives and Investments

The fair values of derivatives and investments that are recorded at fair value on the Condensed Consolidated Balance Sheets at March 31, 2010 and December 31, 2009 are as follows:

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)

				Quoted Prices			Significant
				in Active			Other			Significant
				Market for			Observable			Unobservable
				Identical Assets			Inputs			Inputs
	Total (1)			(Level 1)			(Level 2)			(Level 3)
March 31, 2010				(In thousands)
PNMR and PNM
NDT investments
Cash and equivalents	$	1,907		$	1,907		$	-		$	-
Equity securities:
Domestic value		22,939			22,939			-			-
Domestic growth		40,541			40,541			-			-
International and other		9,845			9,845			-			-
Fixed income securities:
U.S. government		20,448			15,244			5,204			-
Municipals		37,224			-			37,224			-
Corporate and other		8,333			13			8,320			-
Total NDT investments	$	141,237		$	90,489		$	50,748		$	-

PNMR
Commodity derivative assets	$	65,562		$	19,144		$	46,261		$	469
Commodity derivative liabilities		(72,077	)		(35,917	)		(36,088	)		(384	)
Net	$	(6,515	)	$	(16,773	)	$	10,173		$	85

PNM
Commodity derivative assets	$	24,968		$	840		$	24,128		$	-
Commodity derivative liabilities		(7,592	)		(2,966	)		(4,626	)		-
Net	$	17,376		$	(2,126	)	$	19,502		$	-

December 31, 2009
PNMR and PNM
NDT investments
Cash and equivalents	$	2,099		$	2,099		$	-		$	-
Equity securities:
Domestic value		21,458			21,458			-			-
Domestic growth		38,132			38,132			-			-
International and other		9,985			9,985			-			-
Fixed income securities:
U.S. government		20,451			15,135			5,316			-
Municipals		36,901			-			36,901			-
Corporate and other		8,006			-			8,006			-
Total NDT investments	$	137,032		$	86,809		$	50,223		$	-

PNMR
Commodity derivative assets	$	53,032		$	9,097		$	43,510		$	320
Commodity derivative liabilities		(28,574	)		(10,534	)		(17,863	)		(72	)
Net	$	24,458		$	(1,437	)	$	25,647		$	248

PNM
Commodity derivative assets	$	24,498		$	-		$	24,498		$	-
Commodity derivative liabilities		(2,065	)		(958	)		(1,090	)		(17	)
Net	$	22,433		$	(958	)	$	23,408		$	(17	)

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) The Level 1, 2 and 3 columns in the above table are presented based on the nature of each instrument. The total column is presented based on the balance sheet classification of the instruments and reflect unit of account reclassifications between commodity derivative assets and commodity derivative liabilities of $0.3 million for PNMR and zero for PNM at March 31, 2010 and $0.1 million for PNMR and zero for PNM at December 31, 2009. There were no transfers between levels during the three months ended March 31, 2010.

A reconciliation of the changes in Level 3 fair value measurements is as follows:

	PNMR						PNM
	Three Months Ended March 31,						Three Months Ended March 31,
	2010			2009			2010			2009
				(In thousands)
Balance at beginning of period	$	248		$	(409	)	$	(17	)	$	(409	)
Total gains (losses) included in earnings		(377	)		(2,088	)		(128	)		(2,088	)
Total gains (losses) included in other comprehensive income		-			(413	)		-			-
Purchases, issuances, and settlements (1)		214			699			145			632
Balance at end of period	$	85		$	(2,211	)	$	-		$	(1,865	)

Total gains (losses) included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the end of the period	$	(180	)	$	(1,522	)	$	-		$	(1,522	)

(1)	Includes fair value reversal of contracts settled, unearned and prepaid option premiums received and paid during the period for contracts still held at end of period.

Gains and losses (realized and unrealized) for Level 3 fair value measurements included in earnings are reported in operating revenues and cost of energy as follows:

	PNMR						PNM
	Three Months Ended March 31,						Three Months Ended March 31,
	2010			2009			2010			2009
				(In thousands)
Gains (losses) included in earnings:
Electric operating revenues	$	-		$	159		$	-		$	159
Cost of energy		(377	)		(2,247	)		(128	)		(2,247	)
Total	$	(377	)	$	(2,088	)	$	(128	)	$	(2,088	)

Change in unrealized gains or losses related to assets still held at the reporting date:
Electric operating revenues	$	-		$	123		$	-		$	123
Cost of energy		(180	)		(1,645	)		-			(1,645	)
Total	$	(180	)	$	(1,522	)	$	-		$	(1,522	)

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)

(5)	Earnings Per Share

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

	Three Months Ended March 31,
	2010			2009
	(In thousands, except per share amounts)
Earnings (Loss) Attributable to PNMR:
Earnings (loss) from continuing operations	$	(5,214	)	$	16,407
Earnings from continuing operations attributable to Valencia Non-controlling Interest		(3,103	)		(2,579	)
Preferred stock dividend requirements of subsidiary		(132	)		(132	)
Earnings from continuing operations attributable to PNMR		(8,449	)		13,696
Earnings from discontinued operations		-			75,853
Net Earnings (Loss) Attributable to PNMR	$	(8,449	)	$	89,549

Average Number of Common Shares:
Outstanding during period		86,673			86,554
Equivalents from convertible preferred stock (Note 7)		4,778			4,778
Vested awards of restricted stock		95			-
Average Shares - Basic		91,546			91,332
Dilutive Effect of Common Stock Equivalents (a):
Stock options and restricted stock		-			108
Average Shares - Diluted		91,546			91,440

Per Share of Common Stock – Basic:
Earnings (loss) from continuing operations	$	(0.09	)	$	0.15
Earnings from discontinued operations		-			0.83
Net Earnings (Loss)	$	(0.09	)	$	0.98

Per Share of Common Stock – Diluted:
Earnings (loss) from continuing operations	$	(0.09	)	$	0.15
Earnings from discontinued operations		-			0.83
Net Earnings (Loss)	$	(0.09	)	$	0.98

(a)

Due to losses in the three months ended March 31, 2010, no potentially dilutive securities are reflected in the average number of common shares used to compute earnings (loss) per share since any impact would be anti-dilutive. At March 31, 2010, PNMR’s potentially dilutive securities consist of all options and non-vested restricted stock awards (see Note 6).

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)

(6)	Stock-Based Compensation

Information concerning stock-based compensation plans is contained in Note 13 of Notes to Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K.

Stock Options

The following table summarizes activity in stock option plans for the three months ended March 31, 2010:


				Weighted-				Weighted-
				Average		Aggregate		Average
				Exercise		Intrinsic		Remaining
	Shares			Price		Value		Contract Life

Outstanding at beginning of period		4,274,019		$	19.19
Granted		609,708		$	12.23
Exercised		(44,590	)	$	9.22
Forfeited		(4,005	)	$	10.12
Expired		(47,745	)	$	21.84

Outstanding at end of period		4,787,387		$	18.38	$	3,862,672		6.24 years

Exercisable at end of period		3,638,740		$	24.18	$	1,765,637		5.29 years

Available for future grant*		4,626,416

* Includes shares available for grants of restricted stock.

The following table provides additional information concerning stock option activity:

	Three Months Ended March 31,
Options for PNMR Common Stock	2010		2009
	(In thousands, except per share amounts)

Weighted-average grant date fair value of options granted	$	3.05	$	1.62
Total intrinsic value of options exercised during the period	$	159	$	-

The Company uses the Black-Scholes option pricing model to estimate the fair value of stock-based awards with the following weighted-average assumptions for options granted in the three months ended March 31, 2010:

Dividend yield	4.09	%
Expected volatility	41.55	%
Risk-free interest rates	1.36	%
Expected life (years)	4.62

The assumptions above are based on multiple factors, including historical exercise patterns of employees in relatively homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and both the implied and historical volatility of PNMR’s stock price.

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)

Restricted Stock and Performance Shares

The following table summarizes nonvested restricted stock activity for the three months ended March 31, 2010:

				Weighted-
				Average
Nonvested Restricted				Grant-Date
PNMR Common Stock	Shares			Fair Value

Nonvested at beginning of period		193,941		$	11.62
Granted		122,375		$	8.68
Vested		(59,282	)	$	15.12
Forfeited		-		$	-

Nonvested at end of period		257,034		$	9.41

The total fair value of shares of restricted stock that vested during the three months ended March 31, 2010 was $0.9 million.

During 2009 and 2010, the Company issued performance share agreements to certain executives that are based upon the Company achieving specified performance targets for those respective years. In addition during 2009, the Company issued performance share agreements that are based upon achieving specific performance targets for the period 2009 through 2011. The determination of the number of shares ultimately issued depends on the levels at which the performance criteria are achieved and cannot be determined until after the performance periods end. For the targets based only on 2009 performance, the optimal level was attained resulting in 102,375 shares being awarded in 2010, which will vest through 2013. For the targets based only on 2010 performance, the Company would issue a maximum of 109,500 shares if all performance criteria are achieved and the executives remain eligible. For the targets based upon the period 2009 through 2011 performance, the Company would issue a maximum of 46,317 if all performance criteria are achieved and the executives remain eligible.

(7)	Capitalization

Information concerning financing activities is contained in Note 6 of Notes to Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K.

Short-term Debt

At December 31, 2009, PNMR and PNM had revolving credit facilities for borrowings up to $600.0 million under the PNMR Facility and $400.0 million under the PNM Facility that primarily expire in 2012. LBB was a lender under the PNMR Facility and the PNM Facility. LBH, the parent of LBB, has filed for bankruptcy protection. Subsequent to the bankruptcy filing by LBH, LBB declined to fund a borrowing request under the PNMR Facility. A replacement bank has taken the place of LBB under the PNM Facility. In March 2010, the PNMR Facility was amended to remove LBB as a lender and reduce the total capacity under the PNMR Facility to $568.0 million. In addition to the reduction in the PNMR Facility related to LBB, the PNMR Facility and the PNM Facility will reduce by $26.0 million and $14.0 million in 2010 and an additional $25.0 million and $18.0 million in 2011 according to their terms. The Company does not believe amending the PNMR Facility to remove LBB or the scheduled reduction in the facilities will have a significant impact on PNMR’s and PNM’s liquidity. In addition, PNMR and PNM each have a local line of credit amounting to $5.0 million. TNMP has a revolving credit facility for borrowings up to $75.0 million under the TNMP Revolving Credit Facility that expires in April 2011. At March 31, 2010, the weighted average interest rate was 1.49% for the PNMR Facility and 0.88% for the PNM Facility.

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)

Short-term debt outstanding consists of:

	March 31,		December 31,
Short-term Debt	2010		2009
	(In thousands)

PNM
Revolving credit facility	$	178,000	$	118,000
Local lines of credit		-		-
		178,000		118,000
TNMP – Revolving credit facility		-		-
PNMR
Revolving credit facility		109,973		80,000
Local lines of credit		-		-

	$	287,973	$	198,000

At April 30, 2010, PNMR, PNM, and TNMP had $398.9 million, $183.7 million, and $74.7 million of availability under their respective revolving credit facilities and local lines of credit, including reductions of availability due to outstanding letters of credit. Total availability at April 30, 2010, on a consolidated basis, was $657.3 million for PNMR. At April 30, 2010, PNMR and PNM had invested cash of $15.4 million and $9.3 million. TNMP had no such investments.

As of March 31, 2010, TNMP had outstanding borrowings of $17.5 million from PNMR under its intercompany loan agreement.

Financing Activities

In March 2009, TNMP entered into and borrowed $50.0 million under a loan agreement with Union Bank, N. A. (the “2009 Term Loan Agreement”). Through hedging arrangements, TNMP established fixed interest rates for the 2009 Term Loan Agreement of 6.05% for the first three years and 6.30% thereafter. In January 2010, the relationship was modified to reduce the fixed interest rate to 4.80% through March 31, 2012 and to 5.05% thereafter.

In January 2010, PNM entered into a floating-to-fixed interest rate swap with a notional amount of $100.0 million. The effect of this swap is to convert $100.0 million of borrowings under the PNM Facility from an interest rate based on the one-month LIBOR rate to a fixed rate of 1.245% through January 14, 2011, which rate is subject to adjustment in the event PNM’s credit ratings are changed.

These arrangements are accounted for as cash-flow hedges and the March 31, 2010 pre-tax fair values of $(0.5) million for the TNMP hedge and $(0.2) million for the PNM hedge are included in AOCI and in other deferred charges for TNMP and other current liabilities for PNM on the Condensed Consolidated Balance Sheets. Amounts reclassified from AOCI are included in other interest expense. The fair value determinations were made using Level 2 inputs under GAAP and were determined using forward LIBOR curves under the mid-market convention to discount cash flows over the remaining term of the swap agreements.

On February 10, 2010, PNM filed an application with the NMPRC requesting approvals and authorizations to refund up to $403.8 million of callable PCRBs issued by the City of Farmington, New Mexico and the Maricopa County, Arizona Pollution Control Corporation to replace the current bonds with new tax-exempt pollution control revenue bonds. The current bonds have been used to support a portion of the cost of certain pollution control systems, facilities and related improvements at SJGS and PVNGS. The new tax-exempt bonds will be collateralized

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)

by PNM senior unsecured notes, similar to most of the current PCRBs. The NMPRC approved PNM’s request on March 11, 2010. Timing of any refunding and issuing new bonds will depend on market and other conditions.

Convertible Preferred Stock

In November 2008, PNMR issued 477,800 shares of Series A convertible preferred stock. The Series A convertible preferred stock is convertible into PNMR common stock in a ratio of 10 shares of common stock for each share of preferred stock. The Series A convertible preferred stock is entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the preferred stock had been converted into common stock. The Series A convertible preferred stock is entitled to vote on all matters voted upon by common stockholders, except for the election of the Board. In the event of liquidation of PNMR, preferred holders would receive a preference of $0.10 per common share equivalent. After that preference, common holders would receive an equivalent liquidation preference per share and all remaining distributions would be shared ratably between common and preferred holders using the number of shares of common stock into which the Series A convertible preferred stock is convertible. The terms of the Series A convertible preferred stock result in it being substantially equivalent to common stock. Therefore, for earnings per share purposes the number of common shares into which the Series A convertible preferred stock is convertible is included in the weighted average number of common shares outstanding. Similarly, dividends on the Series A convertible preferred stock are considered to be common dividends in the accompanying Condensed Consolidated Financial Statements.

(8)	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 (“PNM Plans” and “TNMP Plans”). PNMR maintains the legal obligation for the benefits owed to participants under these plans.

Information concerning pension and other postretirement plans is contained in Note 12 of Notes to the Consolidated Financial Statements in the 2009 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.

In March 2010, the Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 were signed into law. This legislation expands health care coverage to individuals and will largely be funded through tax increases. The Company does not expect any significant short term impact on our financial statements as a result of the legislation. One provision that will impact certain companies significantly is the elimination of the tax deductibility of the Medicare Part D subsidy. This provision does not have a material impact on the Company’s financial statements.

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 Plans

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

	Three Months Ended March 31,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2010			2009			2010			2009			2010		2009
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	-		$	-		$	105		$	104		$	-	$	15
Interest cost		8,518			8,610			1,913			1,847			263		284
Long-term return on plan assets		(9,339	)		(9,691	)		(1,393	)		(1,458	)		-		-
Amortization of net loss		1,613			955			1,372			822			18		7
Amortization of prior service cost		79			79			(1,036	)		(1,065	)		-		3
Net periodic benefit cost (income)	$	871		$	(47	)	$	961		$	250		$	281	$	309

As a result of the sale of PNM Gas in January 2009, the liability associated with the retiree medical obligation for gas designated employees was transferred to the purchaser and PNM recognized unamortized prior service costs resulting in a $2.9 million gain, which is not included in the net periodic benefit cost above. See Note 12 of Notes to the Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K for additional information regarding the impacts the sale of gas operations had on pension and other postretirement benefits.

PNM made no contributions to its pension plan trust in the three months ended March 31, 2009, made a contribution of $6.5 million for the three months ended March 31, 2010, and anticipates making total contributions of approximately $19.5 million in 2010. Based on current law and estimates of portfolio performance, PNM estimates making additional contributions that total $246.8 million for years 2011- 2014. The estimated contributions were developed using a probabilistically weighted average discount rate of 6.0% to determine the projected benefit obligation under the pension plan. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. For the three months ended March 31, 2010 and 2009, PNM contributed zero and $0.7 million to the trust for other postretirement benefits. PNM expects to make contributions totaling $2.5 million during the year to the trust for other postretirement benefits. Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were $0.4 million in the three months ended March 31, 2010 and 2009, and are expected to total $1.4 million during 2010.

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)

TNMP Plans

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

	Three Months Ended March 31,
	Pension Plan						Other Postretirement Benefits						Executive Retirement Program
	2010			2009			2010			2009			2010			2009
							(In thousands)
Components of Net Periodic
Benefit Cost (Income)
Service cost	$	-		$	-		$	72		$	65		$	-		$	-
Interest cost		1,032			1,099			178			183			13			19
Long-term return on plan assets		(1,449	)		(1,523	)		(129	)		(124	)		-			-
Amortization of net gain		-			-			(49	)		(66	)		(1	)		-
Amortization of prior service cost		-			-			15			15			-			-
Net Periodic Benefit Cost (Income)	$	(417	)	$	(424	)	$	87		$	73		$	12		$	19

TNMP made no contributions to its pension plan trust in the three months ended March 31, 2010 and 2009 and anticipates making contributions of approximately $0.3 million in 2010. Based on current law and estimates of portfolio performance, TNMP estimates making contributions to its pension plan trust that total $10.5 million for years 2011-2014. The estimated contributions were developed using a probabilistically weighted average discount rate of 5.9% to determine the projected benefit obligation under the pension plan. Actual amounts to be funded in the future will be dependent on the actuarial assumptions at that time, including the appropriate discount rate. For the three months ended March 31, 2010 and 2009, TNMP made no contributions to the trust for other postretirement benefits and expects to make contributions totaling $0.4 million during the year. Disbursements under the executive retirement program, which are funded by the Company and considered to be contributions to the plan, were less than $0.1 million in the three months ended March 31, 2010 and 2009, and are expected to total $0.1 million during 2010.

(9)	Commitments and Contingencies

Overview

There are various claims and lawsuits pending against the Company. The Company is also subject to federal, state and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with its business operations. The Company is also involved in various legal 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 proceedings on its results of operations or financial position. It is the Company’s policy to accrue for expected liabilities in accordance with GAAP when it is probable that a liability has been incurred and the amount to be incurred is reasonably estimable. 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. Outside legal costs for these and regulatory matters are recorded when the expenses are incurred. The Company does not expect that any known lawsuits, environmental costs, and commitments will have a material adverse effect on its financial condition, results of operations, or cash flows, although the outcome of litigation, investigations, and other legal proceedings is inherently uncertain.

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, is not reasonably estimable. In some cases, the Company is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, the Company has

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)

assessed these matters based on current information and made judgments concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought, and the probability of success. Such judgments are made subject to the known uncertainty of litigation. The Company has established appropriate reserves 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.

Additional information concerning commitments and contingencies is contained in Note 16 of Notes to Consolidated Financial Statements in the 2009 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, and the DOE is required 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. In November 1997, the U.S. Court of Appeals for the District of Columbia 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 and are currently pursuing those damages claims. The trial in the APS matter began on January 28, 2009 and closing arguments were heard in late May. The court has not indicated when it will reach its decision in the matter. In January 2010, on appeal of another utility’s damages case in which the DOE successfully raised the unavoidable delays defense, the U.S. Court of Appeals for the Federal Circuit reversed the lower court’s decision and concluded that the U.S. Court of Federal Claims, the court handling the APS matter, is bound by the November 1997 District of Columbia Circuit Court decision that prevents the DOE from excusing its delay in performance. PNM currently estimates that it will incur approximately $46.1 million (in 2007 dollars) over the current life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. PNM accrues these costs as a component of fuel expense, meaning that the charges are accrued as the fuel is burned. At March 31, 2010 and December 31, 2009, PNM had $15.2 million and $15.0 million recorded as a liability on its Condensed Consolidated Balance Sheets for interim storage costs.

The Clean Air Act

Regional Haze

The EPA has established rules addressing regional haze and guidelines for BART determinations. The rule calls for all states to establish goals and emission reduction strategies for improving visibility in national parks and wilderness areas. In particular, the alternatives rule defines how an SO 2 emissions trading program developed by the Western Regional Air Partnership, a voluntary organization of western states, tribes and federal agencies, can be used by western states. New Mexico will be participating in the SO 2 program, which is a trading program that will be implemented if SO 2 reduction milestones, which are still being developed, are not met.

In November 2006, the NMED requested a BART analysis for NO X and particulates for each of the four units at SJGS. PNM submitted the analysis to the NMED in early June 2007, recommending against installing additional pollution control equipment on any of the SJGS units beyond those planned at that time, the installation of which was recently completed. PNM has provided additional data in response to requests from the NMED. The NMED is presently reviewing the analysis and supplemental data. Potentially, additional NO X emission reductions could be required. The nature and cost of compliance with these potential requirements cannot be determined at this time.

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 EPA previously requested APS to perform a BART analysis for Four Corners. APS submitted an analysis to the EPA concluding that certain combustion control equipment constitutes BART for Four Corners. Based on the analyses and comments received through EPA’s rulemaking process, the EPA will determine what it believes constitutes BART for Four Corners. The EPA recently issued an Advanced Notice of Proposed Rulemaking (“ANPR”) seeking public comments on its BART determination. The public comment period initially expired in October 2009, but the EPA extended the comment period until March 20, 2010. APS anticipates the EPA will issue proposed and final BART determinations for Four Corners in 2010. The participant owners of Four Corners will have five years after the EPA issues its final determination to achieve compliance with their respective BART requirements. In addition, on February 16, 2010, a group of environmental organizations filed a petition with the U.S. Departments of Interior and Agriculture requesting those agencies to certify to the EPA that visibility impairment in sixteen national park and wilderness areas is reasonably attributable to emissions from Four Corners. If those agencies certify impairment, the EPA is required to evaluate and, if necessary, determine BART for Four Corners. APS’ recommended plan for Four Corners includes the installation of combustion control equipment with an estimated cost to PNM, based on preliminary engineering estimates, of approximately $6.8 million. If the EPA determines that post-combustion controls are required, PNM’s total costs could be up to approximately $69.0 million for Four Corners. The obligation to comply with the EPA’s final BART determinations, coupled with the financial impact of future climate change 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 it. In particular, SCE, a participant in Four Corners, has indicated that certain California legislation may prohibit it from making emission control expenditures at the plant. In order to coordinate with Four Corners’ other scheduled activities, APS is currently implementing portions of its recommended plan on a voluntary basis. Costs related to the implementation of these portions of the recommended plan are included in PNM’s 2010 and 2011 construction expenditure estimates.

While the Company continues to monitor these matters, at the present time, the Company cannot predict whether the agencies will agree with either PNM’s or APS’ BART recommendations. If the agencies disagree with those recommendations for SJGS or Four Corners, the Company cannot predict the nature of the BART controls the agencies may ultimately mandate or the resulting financial or operational impact.

Ozone Non-Attainment

In March 2009, the NMED published its draft recommendation of area designations for the 2008 revised ozone national ambient air quality standard. The draft recommended that San Juan County, New Mexico be designated as non-attainment for ozone. SJGS is situated in San Juan County. However, the NMED subsequently determined that the monitor indicating high ozone levels was not reliable and did not recommend to the EPA that San Juan County be designated as non-attainment. On January 6, 2010, EPA announced it would strengthen the 8-hour ozone standard by setting the standard in a range of 0.060-0.070 parts per million (“ppm”). The EPA will make its final determination of the exact number by August 31, 2010. If EPA sets the standard at 0.070 ppm, it is projected that San Juan County and Dona Ana County will be designated as non-attainment for ozone. If the standard is set lower than 0.070 ppm, other counties in the state, including Bernalillo County, may be designated as non-attainment. A non-attainment designation for Bernalillo County could result in the requirement to reduce NOx emissions from Reeves Station by 2014, and a non-attainment designation for San Juan County could result in the requirement to reduce NO x emissions from SJGS by 2014. The Company cannot predict the outcome of this matter or if additional NO X controls would be required as a result of ozone non-attainment designation.

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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, enacted in 1995 by the Navajo Nation, 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, Window Rock District, challenging the applicability of the Navajo Acts as to Four Corners. The District Court stayed these proceedings pursuant to a request by the parties and the parties are seeking to negotiate a settlement.

In 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. The Four Corners participants believe that the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners. Each of the Four Corners participants filed a petition with the Navajo Nation Supreme Court for review of the operating permit regulations. Those proceedings have been stayed, pending the outcome of the settlement negotiations mentioned above.

In May 2005, APS and the Navajo Nation signed a Voluntary Compliance Agreement (“VCA”) resolving the dispute regarding the Navajo Nation Air Pollution Prevention and Control Act portion of the lawsuit. On March 21, 2006, the EPA determined that the Navajo Nation was eligible for “treatment as a state” for the purpose of entering into a supplemental delegation agreement with the EPA to administer the Clean Air Act Title V, Part 71 federal permit program over Four Corners. The EPA entered into the supplemental delegation agreement with the Navajo Nation on the same day. Because the EPA’s approval was consistent with the requirements of the VCA, APS sought dismissal of the pending litigation in the Navajo Nation Supreme Court, as well as the pending litigation in the Navajo Nation District Court to the extent the claims relate to the Clean Air Act, and the Courts have dismissed the claims accordingly. The agreement does not address or resolve any dispute relating to other aspects of the Navajo Acts.

The Company cannot currently predict the outcome of these matters.

Section 114 Request

On April 6, 2009, APS received a request from the EPA under Section 114 of the Clean Air Act seeking detailed information regarding projects at and operations of Four Corners. This request is part of an enforcement initiative that the EPA has undertaken under the Clean Air Act. The EPA has taken the position that many utilities have made certain physical or operational changes at their plants that should have triggered additional regulatory requirements under the NSR provisions of the Clean Air Act. Other electric utilities have received and responded to similar Section 114 requests, and several of them have been the subject of notices of violation and lawsuits by the EPA. APS has responded to the EPA’s request. The Company is currently unable to predict the timing or content of EPA’s response or any resulting actions.

Santa Fe Generating Station

PNM and the NMED conducted investigations of gasoline and chlorinated solvent groundwater contamination detected beneath the site of the former Santa Fe Generating Station to determine the source of the contamination pursuant to a 1992 settlement agreement between PNM and the NMED.

PNM believes that the data compiled indicates observed groundwater contamination originated from off-site sources. However, to avoid a prolonged legal dispute, PNM entered into settlement agreements with the NMED under which PNM agreed to install a remediation system to treat water from a City of Santa Fe municipal supply well and install an additional extraction well and two new monitoring wells to address gasoline contamination in the groundwater at and in the vicinity of the site. PNM will continue to operate the remediation facilities until the groundwater meets applicable federal and state standards or until such time as the NMED determines that additional

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remediation is not required, whichever is earlier. The well continues to operate and meets federal drinking water standards. PNM is not able to assess the duration of this project.

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 the EPA, which states that neither the source nor extent of contamination has been determined and also states that the source may not be the former Santa Fe Generating Station. The NMED investigation is ongoing. The Company is unable to predict the outcome of this matter.

Coal Combustion By-Products

Regulation

SJGS does not operate any CCB impoundments. SJCC currently disposes of CCBs consisting of fly ash, bottom ash, and gypsum from SJGS in the surface mine pits adjacent to the plant. The Mining and Minerals Division of the New Mexico Energy, Minerals and Natural Resources Department currently regulates mine placement of ash at the mine with federal oversight by the U.S. Department of Interior’s Office of Surface Mining (“OSM”). APS currently disposes of CCBs in ash ponds and dry storage areas at Four Corners, and also sells a portion of its fly ash for beneficial uses, such as a constituent in concrete production. Ash management at the Four Corners plant is regulated by the EPA and the New Mexico State Engineer’s Office.

On May 4, 2010, the EPA issued a proposed rulemaking to regulate CCBs. The proposal asks for public comment on two approaches for regulating CCBs. One option is to regulate CCBs under Subtitle C of the Resource Recovery and Conservation Act (“RCRA”) as a hazardous waste which allows the EPA to create a comprehensive federal program for waste management and disposal of CCBs. The other option is to regulate CCBs under RCRA Subtitle D as a non-hazardous waste. This provides the EPA with the authority to develop performance standards for waste management facilities handling the CCBs and would be enforced primarily through citizen suits. Both options allow for continued use of CCBs in beneficial applications. EPA’s proposal does not address its regulatory determination on the placement of CCBs in surface mine pits for reclamation and indicated that it will work with the OSM to develop federal regulations for placement of CCBs in minefill operations. The proposed rule also states that the EPA and OSM will consider the recommendations of the National Research Council, which, at the direction of Congress, studied the health, safety and environmental risks associated with the placement of CCBs in U.S. coal mines. The 2006 report concluded that the “placement of coal combustion residues in mines as part of coal mine reclamation may be an appropriate option for the disposal of this material”. There will be a 90-day public comment period for the proposal once it is published in the Federal Register.

PNM continues to advocate for the non-hazardous regulation of CCBs under Subtitle D of RCRA. PNM is encouraged by the EPA’s proposed decision to develop separate federal regulations in conjunction with the OSM for mine placement of CCBs and believes the proper place for regulatory oversight should come from the OSM and state mining and mining reclamation agencies. In addition, PNM believes the decision by EPA to consider the conclusions of the National Research Council study in the development of federal regulations regarding placement of CCBs in minefilling operations is a prudent one. PNM cannot predict the outcome of the EPA’s or OSM’s proposed rulemaking regarding CCB regulation, including mine placement of CCBs, or whether these actions will have a material adverse impact on its operations or financial position.

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Sierra Club Actions

In December 2009, PNM and PNMR received a Notice of Intent to Sue (“RCRA Notice”) under the Resource Conservation and Recovery Act ("RCRA") from the Sierra Club. The RCRA Notice was also sent to all SJGS owners and to SJCC, which operates the San Juan Mine that supplies coal to SJGS, and to BHP. Additionally, PNM was informed that SJCC and BHP received a separate notice of intent to sue under the Surface Mine Control and Reclamation Act ("SMCRA") from the Sierra Club. On April 8, 2010, the Sierra Club filed suit in the U.S. District Court for the District of New Mexico against PNM, PNMR, SJCC, and BHP. In the suit, the Sierra Club alleges that activities at SJGS and the San Juan Mine are causing imminent and substantial harm to the environment, including ground and surface water in the region, and that placement of CCBs at the San Juan Mine constitutes "open dumping" in violation of RCRA. The claims under RCRA are asserted with respect to PNM, PNMR, SJCC and BHP. The suit also includes claims under SMCRA, which are directed only against SJCC and BHP. The complaint requests judgment for the following relief: an injunction requiring the parties to undertake certain mitigation measures with respect to the placement of CCBs at the mine or to cease placement of CCBs at the mine; the imposition of civil penalties; and an award of plaintiff’s attorney’s fees and costs. PNM and PNMR plan an aggressive defense of the RCRA claims and cannot predict the outcome of this matter at the present time.

Gila River Indian Reservation Superfund Site

In April 2008, the EPA informed PNM that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. PNM, along with SRP, APS and EPE, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may have been part of an airfield where crop dusting took place. Currently, the EPA is only seeking payment from PNM and other PRPs for past cleanup-related costs involving contamination from the crop dusting. Based upon the total amount of cleanup costs reported by the EPA in its letter to PNM, the resolution of this matter is not expected to have a material adverse impact on PNM’s financial position, results of operations, or cash flows.

Other Commitments and Contingencies

Coal Supply

The coal requirements for SJGS are being supplied by SJCC, a wholly owned subsidiary of BHP. PNM prepays SJCC for coal mined but not yet delivered. At March 31, 2010 and December 31, 2009, prepayments for coal amounted to $32.1 million. APS purchases all of Four Corners’ coal requirements from a supplier with a long-term lease of coal reserves with the Navajo Nation. The Four Corners plant site is leased from the Navajo Nation and is also subject to an easement from the federal government. In 2003, PNM completed a comprehensive review of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal. Based on this study, PNM revised its estimates of the final reclamation costs. In 2009, this study was updated. In addition, the mining contract for Four Corners has been renewed until 2016 and the estimate for decommissioning the Four Corners mine was also revised. Based on the most recent estimates, the total final costs of surface and underground mine reclamation are estimated to be $141.1 million and $23.3 million in future dollars. These amounts exclude contract buyout costs previously paid to SJCC, but otherwise have not been reduced by amounts paid to date. As of March 31, 2010 and December 31, 2009, obligations of $26.2 million and $26.6 million for surface mine reclamation and $2.4 million and $2.3 million for underground mining activities were recognized on PNM’s Condensed Consolidated Balance Sheets using the fair value method to determine the liability.

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PVNGS Liability and Insurance Matters

The PVNGS participants are insured against public liability for a nuclear incident up to $12.6 billion per occurrence. As required by the Price Anderson Nuclear Industries Indemnity Act, the PVNGS participants maintain the maximum available nuclear liability insurance in the amount of $375 million, which is provided by commercial insurance carriers. The remaining balance of $12.2 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. The maximum assessment per reactor under the program for each nuclear incident is $117.5 million, subject to an annual limit of $17.5 million per incident, to be periodically adjusted for inflation. Based on PNM’s 10.2% interest in the three PVNGS units, PNM’s maximum potential assessment per incident for all three units is $36.0 million, with an annual payment limitation of $5.4 million.

The PVNGS participants maintain “all risk” (including nuclear hazards) insurance for property 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. The participants have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (“NEIL”). PNM is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments PNM could incur under the current NEIL policies totals $6.7 million, which amount decreased to $5.8 million effective April 1, 2010. The insurance coverage discussed in this and the previous paragraph is subject to policy conditions and exclusions.

Water Supply

Because of New Mexico’s arid climate and periodic drought conditions, there is a growing concern in New Mexico about the use of water for power plants. PNM has secured water rights in connection with the existing plants at Afton, Luna and Lordsburg. Water availability does not appear to be an issue for these plants at this time.

The “four corners” region of New Mexico, in which SJGS and Four Corners are located, experienced drought conditions during 2002 through 2004 that could have affected the water supply for PNM’s generation plants. In future years, if adequate precipitation is not received in the watershed that supplies the four corners region, the plants could be impacted. Consequently, PNM, APS, and BHP have undertaken activities to secure additional water supplies for SJGS, Four Corners, and related mines. PNM has reached an agreement for a voluntary shortage sharing agreement with tribes and other water users in the San Juan Basin for a term ending December 31, 2012. Further, PNM and BHP have reached agreement on a long-term supplemental contract relating to water for SJGS with the Jicarilla Apache Nation that ends in 2016. APS and BHP have entered into a similar contract for Four Corners. Although the Company does not believe that its operations will be materially affected by the drought conditions at this time, it cannot forecast the weather situation or its ramifications, or how regulations and legislation may impact the Company should 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 the next forty years.

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PVNGS Water Supply Litigation

A summons was served on APS in 1986 that required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons. APS’ rights and the rights of the other PVNGS participants to the use of groundwater and effluent at PVNGS are potentially at issue in this action. 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, the Arizona Supreme Court issued a decision in 2000 affirming the lower court’s criteria for resolving groundwater claims. Litigation on both 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 adverse 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 entitled “State of New Mexico v. United States, et al.”, in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the San Juan River Stream System. The Company was made a defendant in the litigation in 1976. The action is expected to adjudicate water rights used at Four Corners and at SJGS. In 2005, the Navajo Nation and various parties announced a settlement of the Nation’s reserved surface water rights. On March 30, 2009, President Obama signed legislation confirming the settlement with the Navajo Nation. The Company 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. The Company is unable to predict the ultimate outcome of this matter. 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.

Conflicts at San Juan Mine Involving Oil and Gas Leaseholders

SJCC, through leases with the federal government and the State of New Mexico, owns coal interests with respect to the San Juan underground mine. Certain gas producers have leases in the area of the underground coal mine and have asserted claims against SJCC that its coal mining activities are interfering with gas production. SJCC has reached settlement with several gas leaseholders and has other claimants and potential claimants. PNM cannot predict the outcome of existing or future disputes between SJCC and gas leaseholders.

Rights-of-Way Matters

Many of PNM’s electric transmission and distribution facilities are located on lands that require the grant of rights-of-way from governmental entities, Native American tribes, or private parties. Several of the agreements granting the rights-of-way have expired or will expire within the next few years. PNM is actively reviewing these matters and negotiating with certain parties, as appropriate, for the renewal of these rights-of-way. However, there can be no assurance that all of these rights-of-way will be renewed. If PNM is not successful in renewing the rights-of-way on Native American lands, it could be forced to remove its facilities from or abandon its facilities on the property covered by the rights-of-way and seek alternative routes for its transmission or distribution facilities. If rights-of-way on Native American lands are renewed, it is likely they will be renewed at prices that are higher than historical levels, based on current renewal experience. With respect to non-tribal government land and private land, PNM may have condemnation rights. Rights-of-way costs have historically been recovered in rates charged to customers. PNM will seek to recover such costs in future rates.

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Republic Savings Bank Litigation

In 1992, Meadows Resources, Inc. (“MRI”), an inactive subsidiary of PNM, and its subsidiaries (“Plaintiffs”) filed suit against the Federal government in the U.S. Court of Claims, alleging breach of contract arising from the seizure of Republic Savings Bank (“RSB”). RSB was seized and liquidated after Federal legislation prohibited certain accounting practices previously authorized by contracts with the Federal government. The Federal government filed a counterclaim alleging breach of obligation to maintain RSB’s net worth and moved to dismiss Plaintiffs’ claims for lack of standing.

Plaintiffs filed a motion for summary judgment in December 1999 on the issue of liability and on the issue of damages. The Federal government filed a cross motion for summary judgment and opposed Plaintiffs’ motion.

On January 25, 2008, the court entered its opinion granting the Federal government’s motion to dismiss MRI, denying the Federal government’s motion for summary judgment and granting the remaining Plaintiffs’ motion for summary judgment on the issues of liability and damages, awarding the Plaintiffs damages in the amount of $14.9 million. MRI had previously received payment from the FDIC in the amount of $0.3 million. This payment reduced the amount of damages owed to $14.6 million.

The federal government appealed this matter to the U.S. Court of Appeals for the Federal Circuit and Plaintiffs cross-appealed. On October 21, 2009, the Federal Circuit issued its opinion, affirming in part and reversing in part the decision of the Court of Claims, resulting in an award to the Plaintiffs of $9.7 million. The period for requesting rehearing and for filing a petition for certiorari in the U.S. Supreme Court expired in January 2010, and the Circuit Court has issued its mandate, returning the case to the Court of Claims. The government and Plaintiffs filed a Joint Motion for Entry of Final Judgment, which the Court of Claims has granted, entering final judgment for $9.7 million, which was received in April 2010. PNM recorded the amount, net of legal expenses of $1.2 million, as other income in the three months ended March 31, 2010.

Western United States Wholesale Power Market

Various circumstances, including electric power supply shortages, weather conditions, gas supply costs, transmission constraints, and alleged market manipulation by certain sellers, resulted in the well-publicized California and Western markets energy crisis of 2000-2001 and the bankruptcy filings of the Cal PX and PG&E. As a result of the conditions in the Western markets during this time period, between late-2000 and mid-2003, FERC, the California Attorney General, and private parties (collectively, the “California Parties”) initiated investigations, litigation, and other proceedings relevant to PNM and other sellers in the Western markets at FERC and in both California State and Federal District Courts, seeking a determination whether sellers of wholesale electric energy during the crisis period, including PNM, should be ordered to pay monetary refunds to buyers of such energy. These proceedings were pending at FERC as well as before the U.S. Court of Appeals for the Ninth Circuit. PNM participated in these proceedings at FERC, the Federal District Courts and the Ninth Circuit, including filing appeals to that court.

In December 2009, PNM and the California Parties reached an agreement in principle to settle all remaining claims against PNM in these proceedings and on February 11, 2010, PNM entered into a “Settlement and Release of Claims Agreement” (the “Settlement Agreement”), which was filed with FERC on February 12, 2010. The settlement contemplated by this agreement was subject to FERC approval, which was received on April 29, 2010. Because two entities filed comments in opposition to the settlement and FERC rejected the comments, those parties have a right to request rehearing within 30 days of the order and, if any rehearing request is denied, have 60 days from the denial to file an appeal in the U.S. Court of Appeals. The terms of the Settlement Agreement provided, among other things, for PNM to pay to the California Parties the amount of $45.0 million, consisting of the assignment of PNM receivables plus interest as of December 31, 2009 from the Cal ISO and the Cal PX in the amount of $13.1 million plus a cash payment of $31.9 million and for the California Parties to release PNM from claims arising from the California energy crisis of 2000 and 2001. PNM recorded the settlement, which is included

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in other current liabilities, at December 31, 2009. Additionally, the Settlement Agreement provides that certain of California Parties will assume liability that PNM may have to entities that choose not to opt in to the settlement. PNM expressly denies any wrongdoing or culpability with respect to the claims against it that are released by the Settlement Agreement and, in entering into the settlement, does not admit any fault or liability.

On January 15, 2010, PNM transferred the cash payment, which is included in special deposits, to an escrow account established by the California Parties. Pursuant to the Settlement Agreement, the receivables and the cash payment will be distributed to the California Parties and other entities that purchased electricity through the Cal ISO and Cal PX during the relevant time period as settlement funds in accordance with the terms and conditions of the Settlement Agreement.

Complaint Against Southwestern Public Service Company

In September 2005, PNM filed a complaint under the Federal Power Act against SPS. PNM argued that SPS’ rates for sale of interruptible energy were excessive and that SPS had been overcharging PNM for deliveries of energy through its fuel cost adjustment clause practices. PNM also intervened in a complaint proceeding brought by other customers raising similar arguments relating to SPS’ fuel cost adjustment clause practices (the “Golden Spread complaint proceeding”). Additionally, in November 2005, SPS filed an electric rate case at FERC proposing to unbundle and raise rates charged to customers effective July 2006. PNM intervened in the case and objected to the proposed rate increase. In September 2006, PNM and SPS filed a settlement agreement providing for resolution of issues relating to rates for sales of interruptible energy, but not resolving the fuel clause issues. In September 2008, FERC issued its order approving the settlement between PNM and SPS.

In April 2008, FERC issued its order in the Golden Spread complaint proceeding. FERC affirmed in part and reversed in part an ALJ’s initial decision, which had, among other things, ordered SPS to pay refunds to PNM with respect to the fuel clause issues. FERC affirmed the decision of the ALJ that SPS violated its fuel cost adjustment clause tariffs. However, FERC shortened the refund period applicable to the violation of the fuel cost adjustment clause issues. PNM and SPS have filed petitions for rehearing and clarification of the scope of the remedies that were ordered and reversal of various rulings in the order. FERC has not yet acted upon the requests for rehearing or clarification and they remain pending further decision. PNM cannot predict the final outcome of the case at FERC.

Begay v. PNM et al

A putative class action was filed against PNM and other utilities on February 11, 2009 in the United States District Court in Albuquerque. 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. Plaintiffs, including an allottee association, make broad, general assertions that defendants, including PNM, are right-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. The plaintiffs, who have sued the defendants for breach of fiduciary duty, seek a constructive trust. They have also included a breach of trust claim against the United States and its Secretary of the Interior. PNM and the other defendants filed motions to dismiss this action. On March 31, 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. Because this is a final dismissal, this ruling may be appealed to the Tenth Circuit Court of Appeals.

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(10)	Regulatory and Rate Matters

Information concerning regulatory and rate matters is contained in Note 17 of Notes to Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K.

PNMR

First Choice Request for ERCOT Alternative Dispute Resolution

In June 2008, First Choice filed a request for alternative dispute resolution with ERCOT alleging that ERCOT incorrectly applied its protocols with respect to congestion management during the first quarter of 2008. First Choice requested that ERCOT resolve the dispute by restating certain elements of its first quarter 2008 congestion management data and by refunding to First Choice allegedly overstated congestion management charges. The amount at issue in First Choice’s claim can only be determined by running ERCOT market models with corrected inputs but First Choice believes that the amount is significant. ERCOT protocols provide that ERCOT will notify potentially impacted market participants and subsequently consider the merits of First Choice’s allegations. The Company is unable to predict the outcome of this matter.

PNM

Emergency FPPAC

On March 20, 2008, PNM and the IBEW filed a joint motion in PNM’s 2007 Electric Rate Case requesting NMPRC authorization to implement an Emergency FPPAC on an interim basis. On May 22, 2008, the NMPRC issued a final order that approved the Emergency FPPAC with certain modifications. PNM implemented the Emergency FPPAC from June 2, 2008 through the effective date of the 2008 Electric Rate Case order described below.

The Albuquerque Bernalillo County Water Utility Authority and the New Mexico Industrial Energy Consumers Inc. filed notices of appeal to the New Mexico Supreme Court seeking to vacate the NMPRC order approving the Emergency FPPAC. On March 19, 2010, the New Mexico Supreme Court affirmed the NMPRC order approving the Emergency FPPAC.

The NMPRC order approving the Emergency FPPAC required PNM to pay for an audit of PNM’s monthly FPPAC reports and a prudence review of PNM’s fuel and purchased power costs, to be conducted by auditors selected by the NMPRC. Costs of the audit incurred by PNM will be recoverable through future rate proceedings. On February 19, 2010, the audit report of findings and recommendations was submitted to the NMPRC. The report recommended operational changes in several areas but did not identify any imprudent activities or find that PNM’s fuel or purchased power costs were unreasonable. The audit report findings and recommendations are subject to NMPRC review and approval. PNM is unable to predict the outcome of this matter.

The NMPRC order approving the Emergency FPPAC also provided that if PNM’s base load generating units did not operate at or above a specified capacity factor and PNM was required to obtain replacement power to serve jurisdictional customers, PNM would be required to make a filing with the NMPRC seeking approval of the replacement power costs. In its required filing, PNM stated that the costs of the replacement power amounting to $8.0 million were prudently incurred and made a motion that they be approved. The NMPRC staff opposed PNM’s motion and recommended that PNM be required to refund the amount collected. On January 12, 2010, the NMPRC directed the Emergency FPPAC auditor to investigate whether the replacement power costs were prudently incurred. The order also directed PNM to file a response to the auditors’ report, to provide certain additional information, and to show cause why it should not be fined for recovering replacement power costs without prior NMPRC approval. PNM filed its response to the show cause order on February 12, 2010. On February 19, 2010, the auditor’s report on replacement power costs was submitted to the NMPRC. The report concludes that the methodology used to estimate

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the cost of replacement power was reasonable, that PNM purchased power at the lowest reasonable cost, and that outage planning and scheduling and plant operations were reasonable. These findings are subject to NMPRC review and approval. On April 12, 2010, the NMPRC staff filed a request for a hearing on whether the replacement power costs should be approved and whether any penalty should be imposed, to which PNM responded. PNM will continue to assert that its recovery of replacement power costs was proper and did not violate the NMPRC’s order, but is unable to predict the outcome of this matter.

2008 Electric Rate Case

On September 22, 2008, PNM filed a general rate case (“2008 Electric Rate Case”) requesting the NMPRC to approve an increase in electric service rates to all PNM retail customers except those formerly served by TNMP. The case was concluded on June 18, 2009 when a stipulation among the parties that authorized a two-phase rate increase was approved by the NMPRC. On April 1, 2010, PNM implemented the second phase increase of $27.0 million.

Renewable Portfolio Standard

The Renewable Energy Act of 2004 was enacted to encourage the development of renewable energy in New Mexico. The act, as amended, establishes a mandatory renewable energy portfolio standard requiring a utility to acquire a renewable energy portfolio equal to 5% of retail electric sales by January 1, 2006, increasing to 10% by 2011, 15% by 2015 and 20% by 2020. The NMPRC requires renewable energy portfolios to be “fully diversified” beginning in 2011 when no less than 20% of the renewable portfolio requirement must be met by wind energy, no less than 20% by solar energy, no less than 10% by other renewable technologies, and no less than 1.5% by distributed generation. The act provides for streamlined proceedings for approval of utilities’ renewable energy procurement plans, assures utilities recovery of 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. The NMPRC has established a RCT that began at 1% of all customers’ aggregated overall annual electric charges, increasing by 0.2% annually until 2011, at which time it will be 2%, and then increasing by 0.25% annually until reaching 3% in 2015.

On July 1, 2009, PNM filed its annual Renewable Energy Portfolio Procurement Plan for 2010 with the NMPRC. Under the plan, PNM proposed to rely on a mixture of solar, wind, and biogas resources and the purchase of RECs to meet its renewable energy requirements for 2010 and 2011 and committed to file for additional projects later in the year.

In September 2009, PNM entered into settlement discussions with various parties to address issues related to the distributed generation programs, the RCT, and PNM’s prospective additional projects. In recognition of these settlement negotiations, the NMPRC issued an order on September 22, 2009 that rejected certain provisions of PNM’s July 1 st plan and ordered PNM to file a revised plan at the conclusion of the settlement discussions. PNM and several parties to the proceeding filed a stipulation and PNM filed its revised 2010 procurement plan with the NMPRC on January 25, 2010. Under the revised plan, PNM would invest approximately $265 million on solar PV facilities and implement a customer-sited PV distributed generation program to replace its current PV programs. The plan and stipulation are opposed by a number of parties, including the AG and the NMPRC staff. A public hearing on the stipulation and revised procurement plan is scheduled to begin on May 17, 2010. The NMPRC has the authority to approve, reject or modify the proposed plan. PNM cannot predict the outcome of these proceedings.

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)

NMPRC Inquiry on Fuel and Purchased Power Adjustment Clauses

In October 2007, the NMPRC issued a NOI that could lead to the adoption of an amended rule for the implementation of FPPACs for all investor-owned utilities and electric cooperatives in New Mexico. The investor-owned utilities and electric cooperatives have responded to a series of questions and the NMPRC staff made a filing dealing with the need for consistency of FPPACs, streamlining FPPACs, and whether a single FPPAC methodology should be applied to all utilities. Workshops were held to discuss the comments filed by PNM and others and the proposed changes. At the conclusion of the workshop process, the Hearing Examiner presented proposed rule amendments to the NMPRC for its consideration. On April 29, 2010, the NMPRC issued a Notice of Proposed Rulemaking proposing the adoption of the rule amendments that were developed in the workshop process and presented by the Hearing Examiner, and set a schedule for comments and a hearing. The outcome of this proceeding is not expected to have a material impact on PNM.

NMPRC Rulemaking on Disincentives to Energy Efficiency Programs

In January 2008, the NMPRC issued a NOI to identify disincentives in utility expenditures on energy efficiency and measures to address those disincentives, including specific rate making alternatives, and appointed a Hearing Examiner to conduct workshops to develop proposals for possible rule changes. Based on the workshops, the NMPRC issued proposed amendments to its energy efficiency rule. A public hearing was held on June 26, 2009. The NMPRC approved the amended rule on April 8, 2010 to be effective May 3, 2010. The amended rule allows electric utilities to collect rate adders of $0.01 per KWh for lifetime energy savings and $10 per kilowatt for demand savings related to energy efficiency and demand response programs beginning in 2010. In addition, investor-owned electric utilities must make a filing by July 1, 2010 that proposes rate design and ratemaking methods to remove regulatory disincentives or barriers to achieve energy efficiency savings. After such ratemaking measures become effective, the rate adder for energy saving will be reduced to $0.005 per KWh.

On May 5, 2010, PNM filed proposed tariffs under the amended rule. PNM proposed to recover $6.2 million over a twelve-month period following NMPRC approval. PNM is not able to predict the outcome of this proceeding.

PNM Electric Energy Efficiency and Load Management Program s

The NMPRC requires public utilities to obtain approval to implement energy efficiency and load management programs. Costs to implement approved programs are recovered through a rate rider. On September 15, 2008, PNM filed a plan, which included new programs, modifications to existing programs and a request to recover program costs. After proceedings before the NMPRC, a final order approving the programs was issued on May 19, 2009. In August 2009, PNM began recovering the costs of the programs through a rate rider amounting to 1.881% of customers’ bills, before taxes and franchise fees based on program costs of $14.1 million. The new programs are being implemented.

On July 7, 2009, the NMPRC ordered an investigation into whether it is prudent for PNM to continue certain load management programs initiated in 2008 with NMPRC approval, considering its recent addition of supply-side resources. PNM offers these programs through contracts with third-party vendors that contain substantial fees for early termination. On March 10, 2010, the NMPRC issued an order concluding that it would not be prudent to terminate the programs, and remanded the case to a hearing examiner to consider whether freezing the programs at current levels would be possible and, if so, prudent. PNM is unable to predict the outcome of this proceeding.

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)

Rates for Former TNMP Customers in New Mexico

PNM serves the former New Mexico customers of TNMP (“TNMP-NM”) under rates approved by the NMPRC in its order approving PNMR’s acquisition of TNMP. Under that order, rates charged to customers were set through December 31, 2010. In January 2009, the NMPRC directed PNM to estimate the revenue requirement increase that would be reflected in a TNMP-NM rate application for rates effective January 2011. PNM estimated that the rate increase could be between 40% and 56% depending on fuel costs. In April 2009, the NMPRC directed PNM, the NMPRC staff, and other parties to attempt to reach consensus on ways to mitigate the impact of this potential rate increase and appointed a mediator. Several mediations were held but no agreement was reached. In March 2010, the NMPRC issued its Order Initiating Investigation and Requiring Informational Filings to which PNM and other parties filed timely responses. PNM cannot predict the outcome of this matter.

Third-Party Arrangements for Renewable Distributed Generation

On June 16, 2009, the NMPRC initiated a proceeding and requested legal briefs on the topic of whether third-party arrangements for the sale of renewable energy from customer-sited distributed generation facilities were permissible under New Mexico law. On December 31, 2009, the NMPRC issued an order that in part declared that a third party that owns renewable generation equipment that is installed on a utility customer’s premises pursuant to a long-term contract with the customer to supply a portion of that customer’s electricity use, payments for which are based on a kilowatt-hour charge, is not a public utility subject to regulation by the NMPRC. PNM and two other parties appealed the order to the New Mexico Supreme Court.

In early 2010, legislation was enacted that nullified the NMPRC order and, effective January 1, 2011, excludes non-utility power generators from the definition of public utilities under state law, subject to certain limitations as to size and provided that such generators produce renewable energy, the generators are located on the site of the power consumer, and do not utilize retail wheeling of power. A separate provision of the legislation directs the NMPRC to authorize public utilities to establish rates that assure the utilities’ recovery of an appropriate portion of their fixed costs from owners of interconnected generators. After enactment of this legislation, appeals of the NMPRC order were dismissed. On March 9, 2010, the NMPRC issued an order setting workshops for the purpose of obtaining comments and views on implementation of the rate-making aspect of the statute. The workshops are on-going. PNM is unable to predict the outcome of this proceeding.

Application to Hedge Fuel and Purchased Power Costs

In August 2009, PNM filed an application for approval of a plan to manage fuel and purchased power costs by entering into certain forward market transactions relating to the procurement of fuel and purchased power and the sale of excess electrical energy in the wholesale market. PNM’s application sought NMPRC authorization to conduct these activities, which involve hedging practices, and to pass through the costs and benefits of the transactions to jurisdictional customers using PNM’s FPPAC. The NMPRC staff filed testimony recommending approval of PNM’s application with minor modifications. PNM filed rebuttal testimony agreeing with the proposed modifications. A hearing was held on February 23, 2010. The NMPRC approved the program on April 20, 2010.

TNMP

TNMP Competitive Transition Charge True-Up Proceeding

A true-up proceeding to quantify and reconcile the amount of stranded costs that TNMP may recover from its transmission and distribution customers was held at the PUCT. A 2004 PUCT decision established $87.3 million as TNMP’s stranded costs. TNMP and other parties appealed the ruling and the appeals are currently pending before the Texas Supreme Court. TNMP is unable to predict if the Texas Supreme Court will review the decision or the ultimate outcome of this matter.

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)

Interest Rate Compliance Tariff

Following a revision of the interest rate on TNMP’s carrying charge, TNMP filed a compliance tariff to implement the new 8.31% rate. TNMP’s filing proposed to put the new rates into effect on February 1, 2008. Intervenors asserted objections to the compliance filing. PUCT staff urged that the PUCT make the new rate effective as of December 27, 2007 when the PUCT’s order establishing the correct rate became final. After regulatory proceedings, the PUCT issued an order making the new rate retroactive to July 20, 2006. TNMP filed an appeal of this order in the District Court in Austin, Texas. The case is set for hearing on June 29, 2010. While there is inherent uncertainty in this type of proceeding, TNMP believes it will ultimately be successful in overturning any ruling that the effective date should be prior to December 27, 2007.

Transmission Rate Filing

On March 2, 2010, TNMP filed an application to update its transmission rates to reflect changes in its invested capital. The requested increase in total rate base is $33.8 million, with a total revenue requirement increase of $5.5 million. The requested 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 PUCT staff filed a recommendation to approve TNMP’s application on April 6, 2010. The ALJ filed a proposed order approving TNMP’s application on April 13, 2010. The PUCT is expected to rule on the proposed order no later than May 15, 2010.

Energy Efficiency

On October 28, 2009, TNMP filed an application for approval of its 2010 energy efficiency programs and requested recovery through an energy efficiency cost recovery factor. TNMP estimated the costs of its 2010 energy efficiency programs to be $2.6 million and requested to collect this amount based on a per customer charge over 11 months. The PUCT staff and intervenors did not take issue with TNMP’s application. TNMP implemented the factor effective February 1, 2010. On April 30, 2010, TNMP made a similar filing seeking recovery of costs to be incurred in its 2011 programs.

(11) Optim Energy

Optim Energy was created by PNMR and ECJV, a wholly owned subsidiary of Cascade, to serve expanding U.S. markets, principally the areas of Texas covered by ERCOT. PNMR and ECJV each have a 50 percent ownership interest in Optim Energy, a limited liability company. See Note 22 of the Notes to Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K.

On June 1, 2007, Optim Energy entered into a bank financing arrangement with a term of five years, which includes a revolving line of credit. This facility also provides for bank letters of credit to be issued as credit support for certain contractual arrangements entered into by Optim Energy. Cascade and ECJV have guaranteed Optim Energy’s obligations on this facility and, to secure Optim Energy’s obligation to reimburse Cascade and ECJV for any payments made under the guaranty, have a first lien on all assets of Optim Energy and its subsidiaries.

In January 2010, Optim Energy entered into floating-to-fixed interest rate swaps with an aggregate notional amount of $650.0 million. The effect of these swaps is to convert $650.0 million of borrowings under Optim Energy’s credit facility from an interest rate based on the one-month LIBOR rate to a fixed rate of 1.33% through January 7, 2011, exclusive of loan guaranty fees. These swaps are accounted for as cash-flow hedges. At March 31, 2010, these swaps had a pre-tax fair value of $1.2 million, which is included in current liabilities below.

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)

outstanding under its bank financing arrangement and will also use the additional contributions to reduce debt. PNMR has no other commitments or guarantees with respect to Optim Energy.

In June 2009, Optim Energy and NRG Cedar Bayou completed a jointly developed 550 MW combined-cycle natural gas unit at the existing NRG Cedar Bayou Generating Station near Houston. Optim Energy’s share of this unit is 275 MW and its share of the construction costs was $209.6 million. Optim Energy financed its portion of the Cedar Bayou construction with borrowings under its existing credit facility and operating cash flows.

Summarized financial information for Optim Energy is as follows:

Results of Operations

	Three Months Ended March 31,
	2010			2009
	(In thousands)

Operating revenues	$	105,593		$	78,397
Cost of sales		77,297			45,185
Gross margin		28,296			33,212
Non-fuel operations and maintenance expenses		10,520			8,598
Administrative and general expenses		5,612			7,925
Depreciation and amortization expense		12,057			7,659
Taxes other than income tax		3,433			3,329
Operating income (loss)		(3,326	)		5,701
Interest charges		(4,671	)		(2,480	)
Other income (deductions)		65			57
Earnings (loss) before income taxes		(7,932	)		3,278
Income taxes (benefit) (1)		32			162
Net earnings (loss)	$	(7,964	)	$	3,116

50 percent of net earnings (loss)	$	(3,982	)	$	1,558
Amortization of basis difference in Optim Energy		(370	)		(163	)
PNMR equity in net earnings (loss) of Optim Energy	$	(4,352	)	$	1,395

(1) Represents the Texas Margin Tax, which is considered an income tax under GAAP.

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 Position

	March 31,		December 31,
	2010		2009
	(In thousands)

Current assets	$	136,702	$	128,619
Net property plant and equipment		946,423		951,757
Other long-term assets		132,723		137,384
Total assets		1,215,848		1,217,760

Current liabilities		58,293		66,190
Long-term debt		765,000		755,000
Other long-term liabilities		5,807		5,710
Total liabilities		829,100		826,900

Owners’ equity	$	386,748	$	390,860

50 percent of owners’ equity	$	193,374	$	195,430
Unamortized PNMR basis difference in Optim Energy		215		236
PNMR equity investment in Optim Energy	$	193,589	$	195,666

Optim Energy has a hedging program that covers a multi-year period. The level of hedging at any given time varies depending on current market conditions and other factors. Economic hedges that do not qualify for or are not designated as cash flow hedges or normal purchases/sales that are derivative instruments are required to be marked to market. In the first quarter of 2010 and 2009, Optim Energy recorded income of $4.3 million and $9.4 million on the mark-to-market of economic hedges.

Optim Energy individually valued each asset and liability received in the Altura (Twin Oaks) and Altura Cogen transactions and initially recorded them on its balance sheet at the determined fair value. For both transactions, this accounting results in a significant amount of amortization since the acquired contracts’ terms differed significantly from fair value at the date of acquisition and emission allowances, while acquired from government programs without future cost to Optim Energy, had significant market value at the date of acquisition. During the three months ended March 31, 2010 and 2009, Optim Energy recorded amortization of contracts acquired of $4.0 million and $3.1 million, which reduced operating revenues, and amortization expense on emission allowances of $1.3 million and $1.3 million, which is recorded in cost of sales.

The contribution of Altura created a basis difference between PNMR’s recorded investment in Optim Energy and 50 percent of Optim Energy’s equity. While the portion of the basis difference related to contract amortization will only continue through 2010, other basis differences, including a difference related to emission allowances, will continue to exist through the life of the Altura plant. For the three months ended March 31, 2010 and 2009, the basis difference adjustment detailed above relates mainly to contract amortization with insignificant offsets related to the other minor basis difference components.

LCC is Optim Energy’s counterparty in several agreements for power and steam sales . In addition, LCC leases Optim Energy the land for the Altura Cogen facility and provides other services, including water, to that facility. On January 6, 2009, LCC filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The pre-petition net amount due from LCC is immaterial and was fully reserved as of December 31, 2008. LCC has continued to perform under the existing contracts . LCC’s bankruptcy plan was confirmed by the bankruptcy court on April 23, 2010. LCC has filed documents with the bankruptcy court indicating its intent to assume its contracts with Altura Cogen. As part of this process, LCC is required to cure pre-petition defaults under its contracts with Altura Cogen. Altura Cogen and LCC are negotiating the terms of a stipulation to cure these defaults.

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)

(12) Related Party Transactions

PNMR, PNM, TNMP, and Optim Energy are considered related parties as defined under GAAP. PNMR Services Company provides corporate services to PNMR, its subsidiaries, and Optim Energy in accordance with shared services agreements. There is also a services agreement for Optim Energy to provide services to PNMR. Additional information concerning the Company’s related party transactions is contained in Note 20 of the Notes to Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K.

See Note 11 for information concerning Optim Energy. The table below summarizes the nature and amount of related party transactions of PNMR, PNM and TNMP:

	Three Months Ended
	March 31,
	2010		2009
	(In thousands)

Electricity, transmission and distribution related services billings:
TNMP to PNMR	$	9,586	$	9,303

Services billings:
PNMR to PNM*		21,662		17,028
PNMR to TNMP		6,488		5,284
PNM to TNMP		100		133
TNMP to PNMR		121		248
PNMR to Optim Energy		1,438		1,489
Optim Energy to PNMR		18		128

Income tax sharing payments:
PNMR to PNM		-		-
PNMR to TNMP		-		-

Interest payments:
TNMP to PNMR		83		430

* PNM shared services include billings to PNM Gas of $0.9 million for the three months ended March 31, 2009.

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)

(13)	New Accounting Pronouncements

Information concerning recently issued accounting pronouncements that have not been adopted by the Company and could have a material impact, is presented below.

Accounting Standard Update 2010-06 -- Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements

The FASB released amended guidance related to disclosures of fair value measurements. The update requires entities to enhance interim and annual disclosures about fair value measurements, specifically:

-Further disaggregate the level presented for debt and equity securities

-Disclose the amount and reason for significant transfers between fair value categories Level 1 and Level 2

-Disclose information about the purchases, sales, issuances, and settlements for items in Level 3 of the fair value measurements on a gross basis rather than net

The enhanced disclosure for the first two items were effective for the interim period ended March 31, 2010 and are included in Note 4 to the extent applicable. The third item regarding Level 3 information is effective for the interim period ended March 31, 2011 and will be included at that time.

(14) Discontinued Operations

As discussed in Note 2, PNM sold its gas operations, which comprised the PNM Gas segment. Under GAAP, the assets and liabilities of PNM Gas were considered to be held-for-sale and presented as discontinued operations on the accompanying balance sheets. The PNM Gas results of operations are excluded from continuing operations and presented as discontinued operations on the statements of earnings. In accordance with GAAP, no depreciation is recorded on assets held for sale. Summarized financial information for PNM Gas, which has been retroactively adjusted as discussed in Note 1, is as follows:

Results of Operations

	Three Months Ended
	March 31, 2009
	(In thousands)
Operating revenues	$	65,696
Cost of energy		44,698
Gross margin		20,998
Operating expenses		5,817
Depreciation and amortization		-
Operating income		15,181
Other income (deductions)		292
Interest charges		(962	)
Gain on disposal		101,369
Segment earnings before income taxes		115,880
Income taxes		40,027
Segment earnings	$	75,853

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)

(15) Variable Interest Entities

Information concerning the Company’s assessment of potential variable interest entities is contained in Note 9 of Notes to the Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K.

On January 1, 2010, the Company adopted an amendment to GAAP that changes how an enterprise evaluates and accounts for its involvement with variable interest entities. This amendment modifies the determination of the primary beneficiary of a variable interest entity by 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. The amendment also requires continual reassessment of the primary beneficiary of a variable interest entity and increases disclosure requirements. The adoption of this amendment did not change how the Company accounts for its existing arrangements with variable interest entities and the disclosures presented below reflect the requirements of the amendment.

On April 18, 2007, PNM entered into a PPA to purchase all of the electric capacity and energy from Valencia, a natural gas-fired power plant near Belen, New Mexico. Valencia became operational on May 30, 2008. A third-party built, owns and operates the facility while PNM is the sole purchaser of the electricity generated. The total construction cost for the facility was $90.0 million. The term of the PPA is for 20 years beginning June 1, 2008, with the full output of the plant estimated to be 145 MW. 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. PNM estimates that the plant will typically operate during peak periods of energy demand in summer. PNM is obligated to pay fixed O&M and capacity charges in addition to variable O&M charges under this PPA. For the three months ended March 31, 2010 and 2009, PNM paid $4.1 million and $3.3 million for fixed charges and less than $0.1 million and $0.8 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 evaluated the accounting treatment of this arrangement and 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. The significant factors considered in reaching that conclusion are that PNM sources fuel for the plant, controls when the facility operates through its dispatch, and receives the entire output of the plant, which factors directly and significantly impact the economic performance of Valencia. As the primary beneficiary, PNM has consolidated the entity in its financial statements beginning on the commercial operations date. Accordingly, the assets, liabilities, operating expenses, and cash flows of Valencia are included in the consolidated financial statements of PNM although PNM has no legal ownership interest or voting control of the variable interest entity. 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. PNM did not consolidate Valencia prior to May 30, 2008 since PNM had no financial risk.

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)

Summarized financial information for Valencia is as follows:

Results of Operations

	Three Months Ended
	March 31,
	2010			2009
	(In thousands)

Operating revenues	$	4,502		$	4,058
Operating expenses		(1,399	)		(1,479	)
Earnings attributable to non-controlling interest	$	3,103		$	2,579

Financial Position

	March 31,		December 31,
	2010		2009
	(In thousands)

Current assets	$	4,257	$	3,981
Net property, plant and equipment		85,736		86,349
Total assets		89,993		90,330
Current liabilities		663		971
Owners’ equity – non-controlling interest	$	89,330	$	89,359

Changes in Owner’s Equity – Non-controlling Interest

	Three Months Ended
	March 31, 2010
	(In thousands)

Balance at beginning of period	$	89,359
Earnings attributable to non-controlling interest		3,103
Net equity transactions with Valencia’s owner		(3,132	)
Balance at end of period	$	89,330

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. There are currently eight separate lease agreements with eight different trusts whose beneficial owners are five different institutional investors. PNM is not the legal or tax owner of the leased assets. The beneficial owners of the trusts possess all of the voting control and pecuniary interests in the trusts. PNM has an option to purchase the leased assets at appraised value at the end of the leases, but does not have a fixed price purchase option and does not provide residual value guarantees. PNM has 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 may be further extended for up to an additional six years if the appraised remaining useful lives and fair value of the leased assets is greater than parameters set forth in the leases. 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, which, net of amounts that will be returned to PNM through its ownership in related lessor notes, aggregate $123.3 million over the remaining terms of the leases. Under certain circumstances (for example, 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

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)

an event had occurred as of March 31, 2010, PNM could have been required to pay the beneficial owners up to approximately $155.9 million, which would result in PNM taking ownership of the leased assets and termination of the leases. 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 consolidated balance sheets related to the trusts other than the accrual of lease payments between the scheduled payment dates. For additional information regarding these leases, see Risk Factors, MD&A – Off Balance Sheet Arrangements, and Note 7 of the Notes to Consolidated Financial Statements in the Annual Reports on Form 10-K.

PNM has evaluated the PVNGS lease arrangements 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. The significant factors considered in reaching this conclusion are: the periods covered by fixed price renewal options are significantly shorter than the anticipated remaining useful lives of the assets, particularly since it appears reasonably likely that the operating licenses for the plants will be extended for twenty years through 2045 for Unit 1 and 2046 for Unit 2; PNM’s only financial obligation to the trusts is to make the fixed lease payments and the payments do not vary based on the output of the plants or their performance; during the lease term, the economic performance of the trusts is substantially fixed due to the fixed lease payments; PNM is only one of several participants in PVNGS and is not the operating agent for the plants, so does not significantly influence the day to day operations of the plants; furthermore, the operations of the plants, including plans for their decommissioning, are highly regulated by the NRC, leaving little room for the participants to operate the plants in a manner that impacts the economic performance of the trusts; the economic performance of the trusts at the end of the lease terms is dependent upon the fair value and remaining lives of the plants at that time, which are determined by factors such as power prices, outlook for nuclear power, and the impacts of potential carbon legislation or regulation, all which are outside of PNM’s control; and while PNM has some potential benefit from its renewal options, the vast majority of the value at the end of the leases will accrue to the beneficial owners of the trusts, particularly given increases in the value of existing nuclear generating facilities, which have no GHG, resulting from anticipated carbon legislation or regulation.

As discussed in Note 9 of the Notes to Consolidated Financial Statements in the Annual Reports on Form 10-K, PNM has a PPA covering the entire output of Delta, which is a variable interest under GAAP. This arrangement was entered into prior to December 31, 2003 and PNM has been unsuccessful in obtaining the information necessary to determine if it is the primary beneficiary of the entity that owns Delta, or to consolidate that entity if it were determined that PNM is the primary beneficiary. Accordingly, PNM is unable to make those determinations and, as provided in GAAP, continues to account for this PPA as an operating lease. PNM makes fixed and variable payments to Delta under the PPA. PNM also controls the dispatch of the generating plant, which impacts the variable payments made under the PPA and impacts the economic performance of the entity that owns Delta. During the three months ended March 31, 2010 and 2009, PNM incurred fixed payments of $1.4 million and $1.6 million and variable payments of less than $0.1 million and $0.1 million under the PPA. PNM’s only quantifiable obligation under the PPA is to make the fixed payments, which as of March 31, 2010, aggregated $61.5 million through the end of the PPA in 2020. PNM will also pay variable costs, which can not be quantified since the amounts are based on how much the generating plant is in operation. PNM has no other obligations or commitments with respect to Delta.

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). For discussion purposes, this report will use 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

BUSINESS AND STRATEGY

Overview

PNMR provides electricity and energy efficiency products and services in both regulated and unregulated markets to help customers meet and manage their energy needs. PNM sold its gas operations on January 30, 2009 and is now focused on its regulated electric business going forward.

PNM

Critical to PNMR’s success for the foreseeable future is the financial health of PNM, PNMR’s largest subsidiary, which is highly dependent on continued favorable regulatory treatment. PNM filed its 2008 Electric Rate Case requesting the NMPRC to approve an increase in electric service rates of $123.3 million. PNM also proposed a more traditional FPPAC. In June 2009, the NMPRC approved a stipulation resolving all issues in the rate case. The approved stipulation allowed for an increase in annual non-fuel revenues of $77.1 million, 65% of which was implemented for bills rendered beginning July 1, 2009 and the remainder of which was implemented April 1, 2010. As an offset to the non-fuel revenue increase, PNM implemented a credit to customers totaling $26.3 million, representing the amount of revenues from past sales of SO 2 allowances, over 21 months beginning July 1, 2009. The stipulation also provided for a more traditional FPPAC that went into effect with the new rates.

PNM anticipates a trend toward increasing costs of providing electric service and a period of plant expansion, primarily from renewable energy sources under the renewable energy portfolio requirements established pursuant to New Mexico’s Renewable Energy Act and related regulations of the NMPRC. PNM also anticipates increases in costs related to renewals of rights of way on Native American lands, pension and benefits, and depreciation at SJGS. PNM will seek to recover these increased costs of providing service to regulated customers through future rate filings, which may occur more frequently than in the past. The impact that rate increases may have on customers’ usage and their ability to pay is unknown.

Senate Bill 477 (“SB 477”) became effective in June 2009. SB 477 is designed to promote more timely recovery of reasonable costs of providing utility service in two ways. First, SB 477 requires the NMPRC, when setting rates, to use the test period that best reflects the conditions the utility will experience when new rates are anticipated to go into effect. The NMPRC is required to give due consideration that a future test period may be the one that best meets this requirement. A future test period is defined as a twelve month period beginning no later than the date a proposed rate change is expected to take effect. Traditionally, the NMPRC has used a historical test period, adjusted for known and measurable changes occurring within five to six months after the end of the test period, which reflects costs that could be up to two years old at the time new rates become effective. It is possible, however, that NMPRC staff or intervenors would argue that continued use of a historical test period, adjusted for known and measurable changes, best meets the requirement. Second, SB 477 requires the NMPRC to include construction work in progress in rate base, without an offset for allowance for funds used during construction, for environmental improvement projects and generation and transmission projects for which a certificate of public convenience and necessity has been issued. This provision will allow utilities to collect costs as projects are being built rather than waiting until they are finished to include them in rate base, so long as the projects will be in service no later than two years after the filing date of the rate case.

PNM anticipates filing a rate case with the NMPRC in mid 2010 using a future test period as allowed by SB 477. The magnitude of amounts to be requested is currently unknown and PNM cannot predict the amount that the NMPRC will approve. PNM also anticipates filing a rate case with FERC in the fourth quarter of 2010 for its firm transmission customers. The magnitude of the rate increase is currently unknown and PNM cannot predict the amount FERC will approve.

The use of a future test year should help PNM to mitigate the adverse effects of regulatory lag, which is inherent when using a historical test year, by focusing on what costs are likely to be when new rates go into effect rather than what they were in the past. The mitigation of the adverse effects of regulatory lag should result in PNM’s earnings more closely approximating the rate of return allowed by the NMPRC. PNMR believes that achieving earnings that approximate its allowed rate of return is an important factor in attracting equity investors, as well as being an important metric utilized by credit rating agencies and financial analysts. PNM’s debt securities are currently rated below investment grade by S&P, although Moody’s rates PNM’s debt at the lowest level of investment grade. PNM currently expects it will access the credit and capital markets in order to finance at least a portion of the anticipated construction expenditures discussed in Capital Requirements under Liquidity and Capital Resources below. To the extent such financing includes the issuance of debt securities that are rated below investment grade, the debt would carry a higher interest rate than if the securities were investment grade. Those higher interest costs would then be included in requests for rate relief, placing additional upward pressure on rates charged to customers.

As with any forward looking financial information, utilizing a future test year in a rate filing presents challenges that are inherent in the forecasting process. PNM will need to forecast both operating and capital expenditures that will necessitate reliance on many assumptions concerning future conditions. Among others, these would include assumptions about future economic conditions in PNM’s service territory, levels of employment, load growth and conservation, weather, usage patterns of customers, availability and technology regarding renewable energy sources, interest rates and other financing costs, access to capital markets, inflation, and impacts of regulatory actions. In the rate making process, PNM’s assumptions will be subject to challenge by regulators and intervenors who may assert different interpretations or assumptions.

PNM also serves customers in New Mexico formerly served by TNMP. When PNMR acquired TNMP, PNM was required to maintain the former TNMP customers under rates separate from the rest of PNM. Pursuant to a stipulation approved by the NMPRC, PNM was prohibited from consolidating the cost of service for the two areas until January 1, 2015, unless the consolidation would not result in shifting more than $1.5 million in revenue requirements from the former TNMP customers to other PNM customers. In addition, the stipulation provided that PNM would not seek rate changes for the former TNMP customers that would go into effect before January 1, 2011. During 2009, the NMPRC requested the parties to the stipulation meet to discuss ways and means of mitigating possible large rate increases to the former TNMP customers that may occur when the rate moratorium expires. The parties have been meeting periodically under the direction of a NMPRC Hearing Examiner, who was appointed by the NMPRC to serve as mediator for the discussions. See Note 10.

TNMP

TNMP’s financial health is also highly dependent on continued favorable regulatory treatment. In August 2008, TNMP filed with the PUCT for an $8.7 million increase in revenues, which was subsequently amended to request an additional revenue increase of $15.7 million. In June 2009, TNMP and the other parties in the rate case reached a unanimous settlement resolving all issues in the rate case and permitting TNMP to increase its rates by $12.7 million annually. This increase reflects interest and other costs associated with debt refinancing in March 2009 and the settlement adjusts the interest rate TNMP is allowed to collect on its CTC to reflect those costs. The rate increase includes recovery of Hurricane Ike restoration costs plus carrying costs over five years. The settlement was approved by the PUCT in August 2009. TNMP now has the ability to update its transmission rates annually to reflect changes in its invested capital. TNMP filed a request to update its rates under this provision in March 2010, increasing annual revenues by $5.5 million. 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. See Note 10. TNMP anticipates filing for its next general rate case in the third quarter of 2010.

Environmental Sustainability

The Company’s focus on the electric businesses also includes environmental sustainability efforts. These efforts include environmental upgrades, improving energy efficiency, expanding the renewable energy portfolio of generation resources, and proactively addressing climate change. In early 2009, PNM completed environmental upgrades to each of the four units at SJGS. PNM’s share of the costs of these upgrades, which reduced the levels of NO X , SO 2 , and mercury emissions, amounted to $161 million. As described in Note 10, PNM is subject to the renewable portfolio standard established by New Mexico’s Renewable Energy Act and related regulations issued by the NMPRC, which require utilities to achieve certain levels of energy sales from renewable sources within its generation mix, including wind, solar, distributed generation, and other sources. PNM is actively engaged in activities to meet the NMPRC standard. PNM has also established various programs to promote energy efficiency, subject to the approval of the NMPRC. The Company monitors initiatives regarding legislation or regulation regarding climate change, including GHG, and participates in organizations and forums concerning climate change. The Company has expressed support for the Waxman-Markey bill and is generally supportive of a federal program that includes an economy-wide system of limitations on GHG that would include a cap and trade provision and a system of allowances and offsets designed to mitigate rate increases to utility customers. The Company is exploring various methods to mitigate its GHG in anticipation of climate change legislation or regulation, including increasing energy efficiency programs and increased reliance on renewable energy resources. See Climate Change Issues under Other Issues Facing the Company below for additional discussion of climate change matters. All of these efforts involve costs that the Company believes should be recoverable through rates charged to customers to the extent the costs are attributable to regulated operations. However, recovery of these costs is subject to the approval of regulators and will cause upward pressure on rates.

First Choice

As a REP, First Choice operates in the highly competitive Texas retail market, which experienced extreme price volatility and transmission congestion in 2008. ERCOT controls the transmission of power in the areas that First Choice supplies. ERCOT historically has operated through a series of geographic zones, which has led to congestion of the transmission system when large volumes of power were being transmitted between zones. Congestion tends to drive prices up in the spot market. These anomalies negatively impacted the margins realized from end use customers. These conditions were exacerbated by the impacts of Hurricane Ike and depressed economic conditions resulting in very high levels of customer turnover and levels of uncollectible accounts significantly higher than historical experience. ERCOT has made changes in its control protocols and is scheduled to change from the zonal system to a nodal system in December 2010, both of which should reduce congestion and price volatility. During 2009 and early 2010, the Texas retail market was more stable and First Choice does not anticipate the levels of extreme congestion and price volatility will reoccur in the near future. In addition, both power and natural gas prices decreased significantly, resulting in a substantial increase in margins realized by First Choice. These factors and increased focus on growing commercial accounts, customer credit standards, and improved customer service have improved results of operations at First Choice. First Choice expects market conditions to continue to be a key factor for the business and believes margins will return to more historic levels during 2010.

Economic Conditions

In the last half of 2008 and early 2009, global economic conditions deteriorated dramatically, encompassing the U.S. residential housing market, and global and domestic equity and credit markets, which resulted in reduced usage of electricity by the Company’s customers. Although New Mexico and Texas do not seem to be impacted as greatly as some other areas of the United States, with unemployment rates that are somewhat lower than the rest of the nation, the territories served by the Company’s electric businesses have been impacted by the recession and general economic downturn. The Company believes that electric sales volume will be relatively flat for the immediate future.

The unprecedented disruption in the credit markets in late 2008 and early 2009 had a significant adverse impact on numerous financial institutions, including several of the financial institutions that have dealings with the Company. However, at this time, the Company’s existing liquidity instruments have not been materially impacted by the credit environment and management does not expect that it will be materially impacted in the near future. The Company’s revolving credit facilities expire in 2011 and 2012 and will need to be renegotiated or replaced in order to provide sufficient liquidity to finance operations and construction expenditures. The availability of such

credit facilities and their terms and conditions will depend on the credit markets at that time, as well as the Company’s credit ratings and operating results.

Optim Energy

PNMR’s 50 percent ownership of Optim Energy allows it to participate in the operation of Optim Energy’s assets and business and the formulation of Optim Energy’s business strategy. Optim Energy owns electric generating assets in one of the nation’s growing power markets. In 2009, Optim Energy was affected by continuing adverse market conditions, primarily low natural gas and power prices, and changed its near-term focus. Optim Energy is currently focused on utilizing cash flow from operations to reduce debt and optimizing its current generation assets as a stand-alone independent power producer. The goal is to position Optim Energy to optimize its performance under current market conditions with the expectation of being able to take advantage of any economic recovery in the power and gas markets over the next several years.

Any decisions in the future to grow capacity will be subject to the approval of both of Optim Energy’s members and will be based on many then-existing market and other factors, including the cost to acquire or construct capacity, the anticipated demand for power, the anticipated market prices for power, the ability and cost to deliver power to the anticipated markets, and Optim Energy’s financial resources.

RESULTS OF OPERATIONS

Executive Summary

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

	Three Months Ended March 31,
	2010			2009		Change
	(In millions, except per share amounts)
Earnings (loss) from continuing operations	$	(8.4	)	$	13.7	$	(22.1	)
Earnings from discontinued operations, net of income taxes		-			75.9		(75.9	)
Net earnings (loss)	$	(8.4	)	$	89.5	$	(97.9	)
Average common and common equivalent shares outstanding		91.5			91.4		0.1
Earnings (loss) from continuing operations per diluted share	$	(0.09	)	$	0.15	$	(0.24	)
Net earnings (loss) per diluted share	$	(0.09	)	$	0.98	$	(1.07	)

The components of the change in earnings (loss) from continuing operations attributable to PNMR (in millions) are:

PNM Electric	$	9.4
TNMP Electric		0.2
First Choice		(14.5	)
Corporate and Other		(13.7	)
Optim Energy		(3.5	)
Net change	$	(22.1	)

Detailed information regarding the changes in earnings (loss) from continuing operations are included in the segment information below. The after-tax changes relate primarily to losses on unrealized economic hedges at First Choice which decreased earnings by $17.9 million in 2010 compared with gains of $0.3 million in 2009. In addition, gains at Corporate and Other in 2009 relating to a $9.1 million fee received upon termination of the proposed CRHC acquisition and $4.5 million on the re-acquisition of $157.4 million of PNMR’s 9.25% senior unsecured notes were partially offset by a $5.1 million gain at PNM for a settlement associated with the Republic Savings Bank litigation in 2010.

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.

PNM Electric

The table below summarizes operating results for PNM Electric:

	Three Months Ended March 31,
	2010			2009			Change
	(In millions)
Total revenues	$	230.5		$	232.0		$	(1.5	)
Cost of energy		86.4			101.5			(15.1	)
Gross margin		144.1			130.4			13.6
Operating expenses		108.8			97.5			11.3
Depreciation and amortization		22.9			22.4			0.4
Operating income		12.5			10.5			2.0
Other income (deductions)		16.1			1.0			15.1
Interest charges		(18.1	)		(17.2	)		(0.9	)
Earnings (loss) before income taxes		10.5			(5.7	)		16.2
Income (taxes) benefit		(2.9	)		3.3			(6.3	)
Valencia non-controlling interest		(3.1	)		(2.6	)		(0.5	)
Preferred stock dividend requirements		(0.1	)		(0.1	)		-
Segment earnings (loss)	$	4.3		$	(5.1	)	$	9.4

The table below summarizes the significant changes to total revenues, cost of energy, and gross margin:

	2010/2009 Change
	Total				Cost of			Gross
	Revenues				Energy			Margin
				(In millions)
Retail rate increases	$	10.6			$	6.6		$	4.0
Retail load, fuel and transmission		(4.0	)			(9.1	)		5.1
Unregulated margins		(3.2	)			(6.7	)		3.5
Net unrealized economic hedges		(4.9	)			(5.5	)		0.6
Consolidation of Valencia PPA		-				(0.4	)		0.4
Total increase (decrease)	$	(1.5	)		$	(15.1	)	$	13.6

The following table shows PNM Electric operating revenues by customer class, including intersegment revenues and average number of customers:

	Three Months Ended March 31,
	2010			2009		Change
	(In millions, except customers)
Residential	$	84.4		$	73.7	$	10.7
Commercial		72.9			70.0		2.9
Industrial		20.3			19.0		1.3
Public authority		4.4			4.4		-
Other retail		2.1			2.9		(0.8	)
Transmission		9.7			7.7		2.0
Firm requirements wholesale		8.2			7.6		0.6
Other sales for resale		30.6			43.5		(12.9	)
Mark-to-market activity		(2.1	)		3.2		(5.3	)
	$	230.5		$	232.0	$	(1.5	)
Average retail customers (thousands)		501.0			497.9		3.1

The following table shows PNM Electric GWh sales by customer class:

	Three Months Ended March 31,
	2010		2009		Change
	(Gigawatt hours)
Residential		858.4		795.7		62.7
Commercial		881.2		855.6		25.6
Industrial		349.8		355.2		(5.4	)
Public authority		54.2		51.7		2.5
Firm requirements wholesale		177.2		183.6		(6.4	)
Other sales for resale		541.2		1,060.1		(518.9	)
		2,862.0		3,301.9		(439.9	)

The results of operations of PNM Electric are primarily driven by the rate making decisions and other actions of the NMPRC. In 2010, margins improved due to the implementation of new rates in PNM’s 2008 Electric Rate Case. The first phase implemented 65% of a $77.1 million non-fuel base rate increase, for retail customers except those formerly served by TNMP, beginning July 1, 2009. PNM implemented the remaining 35% or $27.0 million increase on April 1, 2010.

Increases in retail loads, driven by cooler temperatures and an increase in usage per customer, as well as higher transmission revenues from new transmission contracts, increased revenues and margins. Decreases to revenues were driven by lower off-system sales volumes due to lower available excess generation resulting from outages at baseload facilities. These reductions in revenues, along with an increase in economy purchase volumes to meet load requirements were offset through the FPPAC for retail customers, except those customers formerly served by TNMP and certain wholesale customers.

The revenues and costs associated with Luna, Lordsburg, and the Valencia PPA were included in unregulated margins prior to May 2009, when the costs of those plants, net of off-system sales, began being recovered through the regulatory process. In 2009, unregulated margins were negatively impacted due to the fixed demand charges associated with the Valencia PPA.

PNM Electric analyzes results associated with the Valencia PPA as costs of energy. Under GAAP, the Valencia PPA is consolidated, which results in costs being reflected as operating expenses and non-controlling interest that would have been included in cost of energy if the Valencia PPA was not consolidated.

Increases in operating expenses are driven by planned outage costs at Four Corners and increased outage and maintenance costs incurred at SJGS due to unplanned repairs on San Juan Unit 2, higher medical and pension plan costs, lower capitalized administrative and general costs due to lower capital spending, and an increase in allocated corporate costs.

Depreciation and amortization expense increased due to higher utility plant and amortization of certain regulatory assets, which are partially offset by lower depreciation expense on PVNGS and Reeves Station due to extension of useful lives.

Other income increases are primarily due to an $8.5 million settlement associated with the Republic Savings Bank litigation and $6.6 million related to improved performance of the NDT assets.

TNMP Electric

The table below summarizes the operating results for TNMP Electric:


	Three Months Ended March 31,
	2010			2009			Change
	(In millions)
Total revenues	$	48.2		$	41.2		$	7.0
Cost of energy		9.1			8.6			0.5
Gross margin		39.1			32.6			6.5
Operating expenses		18.8			17.9			0.8
Depreciation and amortization		10.1			8.6			1.5
Operating income		10.2			6.1			4.2
Other income (deductions)		0.3			0.4			(0.0	)
Interest charges		(7.9	)		(4.1	)		(3.8	)
Earnings before income taxes		2.7			2.4			0.3
Income (taxes)		(1.1	)		(1.0	)		(0.1	)
Segment earnings	$	1.6		$	1.4		$	0.2

The table below summarizes the significant changes to total revenues, cost of energy, and gross margin:

	2010/2009 Change
	Total		Cost of		Gross
	Revenues		Energy		Margin
	(In millions)
Rate increases	$	1.3	$	-	$	1.3
Customer usage/load		3.2		-		3.2
Other		2.5		0.5		2.0
Total increase (decrease)	$	7.0	$	0.5	$	6.5

The following table shows TNMP Electric operating revenues by customer class, including intersegment revenues, and average number of customers:

	Three Months Ended March 31,
	2010		2009		Change
	(In millions, except customers)
Residential	$	18.9	$	14.4	$	4.5
Commercial		17.5		16.0		1.5
Industrial		3.0		3.0		-
Other		8.8		7.8		1.0
	$	48.2	$	41.2	$	7.0
Average customers (thousands) (1)		228.5		228.1		0.4

(1)

Under TECA, customers of TNMP Electric in Texas have the ability to choose First Choice or any other REP to provide energy. The average customers reported above include 79,193 and 89,895 customers of TNMP Electric for the three months ended March 31, 2010 and 2009, who have chosen First Choice as their REP. These customers are also included in the First Choice segment.

The following table shows TNMP Electric GWh sales by customer class:

	Three Months Ended March 31,
	2010		2009		Change
	(Gigawatt hours (1) )
Residential		611.5		509.8		101.7
Commercial		476.4		460.3		16.1
Industrial		516.8		424.1		92.7
Other		24.8		25.8		(1.0	)
		1,629.5		1,420.0		209.5

(1)	The GWh sales reported above include 249.5 and 248.3 GWhs for the three months ended March 31, 2010 and 2009 used by customers of TNMP Electric, who have chosen First Choice as their REP. These GWhs are also included below in the First Choice segment.

Implementation of new rates on September 1, 2009 and an increase in retail sales associated with cooler temperatures increased revenues and margins. In March 2010, TNMP filed a request to update its transmission rates to reflect changes in its invested capital. The request would increase annual rates by $5.5 million and is before the PUCT for approval, which is expected in second quarter 2010.

Operating expenses increased largely from higher self insurance premiums and losses, as well as corporate allocation costs, partially offset by lower tree trimming expenses.

Depreciation and amortization increased related to the amortization of Hurricane Ike restoration costs, which are covered in new rates discussed above, and higher depreciation costs due to increases in transmission plant.

Interest charges increased primarily due to higher interest rates on long-term debt issued in March 2009. The higher cost of debt is reflected in the rate increase discussed above.

PNM Gas

The table below summarizes the operating results for PNM Gas, which is classified as discontinued operations in the Condensed Consolidated Statements of Earnings (Loss):

	Three Months Ended
	March 31, 2009
	(In millions)
Total revenues	$	65.7
Cost of energy		44.7
Gross margin		21.0
Operating expenses		5.8
Depreciation and amortization		-
Operating income		15.2
Other income (deductions)		0.3
Interest charges		(1.0	)
Gain on disposal		101.4
Earnings before income taxes		115.9
Income (taxes)		(40.0	)
Segment earnings	$	75.9

PNM completed the sale of the PNM Gas business on January 30, 2009. PNM Gas is reported as discontinued operations as required under GAAP. PNM Gas purchased natural gas in the open market and sold it at no profit to its sales-service customers. As a result, increases or decreases in gas revenues driven by gas costs did not impact the gross margin or operating income of PNM Gas. Increases or decreases to gross margin caused by changes in sales-service volumes represented margin earned on the delivery of gas to customers based on regulated rates.

As a result of the sale, the above table reflects operations from the PNM Gas business from January 1 through January 30, 2009. Milder weather combined with lower usage-per customer reduced overall sales volumes in 2009. A pre-tax gain of $101.4 million, which reflects the retroactive adjustment discussed in Note 1, was recognized on the sale of the PNM Gas business.

First Choice

The table below summarizes the operating results for First Choice:

	Three Months Ended March 31,
	2010			2009			Change
	(In millions)
Total revenues	$	114.4		$	122.2		$	(7.8	)
Cost of energy		105.0			80.4			24.6
Gross margin		9.4			41.8			(32.4	)
Operating expenses		20.4			29.3			(8.9	)
Depreciation and amortization		0.3			0.5			(0.3	)
Operating income (loss)		(11.3	)		11.9			(23.2	)
Other income (deductions)		-			-			-
Interest charges		(0.3	)		(1.0	)		0.7
Earnings (loss) before income taxes		(11.6	)		10.9			(22.6	)
Income (taxes) benefit		4.2			(3.9	)		8.1
Segment earnings (loss)	$	(7.5	)	$	7.0		$	(14.5	)

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

	2010/2009 Change
	Total			Cost of			Gross
	Revenues			Energy			Margin
	(In millions)
Weather	$	11.3		$	7.5		$	3.8
Customer growth/usage		(6.2	)		(4.9	)		(1.3	)
Retail margins		(13.0	)		(6.3	)		(6.7	)
Trading margins		0.1			-			0.1
Unrealized economic hedges		-			28.3			(28.3	)
Total increase (decrease)	$	(7.8	)	$	24.6		$	(32.4	)

The following table shows First Choice operating revenues by customer class, including intersegment revenues, and actual number of customers:

	Three Months Ended March 31,
	2010		2009			Change
	(In millions, except customers)
Residential	$	74.7	$	76.0		$	(1.3	)
Mass-market		4.2		8.3			(4.1	)
Mid-market		30.9		32.1			(1.2	)
Trading gains (losses)		-		(0.1	)		0.1
Other		4.6		5.9			(1.3	)
	$	114.4	$	122.2		$	(7.8	)
Actual customers (thousands) (1,2)		221.4		246.7			(25.3	)

(1)	See note above in the TNMP Electric segment discussion about the impact of TECA.

(2)	Due to the competitive nature of First Choice’s business, actual customer count at March 31 is presented in the table above as a more representative business indicator than the average customers that are shown in the table for TNMP customers.

The following table shows First Choice GWh electric sales by customer class:

	Three Months Ended March 31,
	2010		2009		Change
	(Gigawatt hours) (1)
Residential		550.1		501.8		48.3
Mass-market		26.6		42.0		(15.4	)
Mid-market		251.2		248.7		2.5
Other		2.0		2.3		(0.3	)
		829.9		794.8		35.1

(1)	See note above in the TNMP Electric segment discussion about the impact of TECA.

During 2010, favorable weather and increased MWh sales were offset by a decrease in the average sales price and a reduction in the number of customers resulting in decreased operating revenues compared to 2009. Lower purchased power costs and fewer customers in 2010 resulted in decreased cost of energy.

First Choice manages its exposure to fluctuations in market energy prices by matching sales contracts with supply instruments designed to preserve targeted margins. Accordingly, First Choice has forward energy contracts in place to cover the future load requirements for most of its fixed price sales contracts. Gains or losses on unrealized economic hedges represent changes in unrealized fair value estimates related to these forward energy contracts. Changes in the fair value of supply contracts that are not designated or are not eligible for hedge or normal purchase/sales accounting are marked to market through current period earnings as required by GAAP. During the first quarter of 2010, market energy prices decreased significantly, which resulted in GAAP losses on certain of First Choice's forward supply contracts. First Choice is not required to mark the related fixed price sales contracts to market, which would likely show offsetting gains as market energy prices decrease. First quarter losses on unrealized economic hedges decreased segment earnings by $27.8 million in 2010 compared with gains of $0.5 million in 2009. These mark-to-market losses are not necessarily indicative of the amounts that will be realized upon settlement or the retail margin First Choice will realize.

The allowance for uncollectible accounts and related bad debt expense is based on collections and write-off experience. In late 2008 and early 2009, the customer default rates experienced were significantly above historic levels due to macroeconomic conditions, higher average final bills, and an increase in customer churn. Recently, lower customer departures, lower default rates and significantly lower average final bills attributable to lower sales prices have reduced bad debts. As a result, bad debt expense in the first quarter of 2010 was $8.5 million lower than in 2009. This reduction can be partially attributed to several initiatives undertaken by management to reduce bad debt expense. These initiatives include efforts to reduce the default rate experienced for customers switching to another REP and increased focus on identifying new customer prospects that are more likely to demonstrate desired payment behavior. First Choice is focusing its marketing efforts on commercial customers and customers with established payment patterns. First Choice has also increased the credit score required to become a customer and expanded the circumstances where customers are required to provide advance deposits to obtain service, or both. In addition, possible regulatory changes are under discussion with the PUCT that would impede a customer's ability to switch REPs until past due balances are paid.

First Choice had lower customer acquisition expenses and support services costs in the first quarter of 2010 compared 2009.

Corporate and Other

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

	Three Months Ended March 31,
	2010			2009			Change
	(In millions)
Total revenues	$	(9.6	)	$	(9.5	)	$	(0.1	)
Cost of energy		(9.5	)		(9.3	)		(0.2	)
Gross margin		(0.1	)		(0.2	)		0.1
Operating expenses		(3.3	)		(6.1	)		2.9
Depreciation and amortization		4.1			4.5			(0.5	)
Operating income (loss)		(0.8	)		1.4			(2.3	)
Equity in net earnings (loss) of Optim Energy		(4.4	)		1.4			(5.7	)
Other income (deductions)		(1.4	)		20.2			(21.6	)
Interest charges		(5.2	)		(6.6	)		1.5
Earnings (loss) before income taxes		(11.7	)		16.4			(28.1	)
Income (taxes) benefit		4.8			(6.1	)		10.8
Segment earnings (loss)	$	(7.0	)	$	10.3		$	(17.3	)

The Corporate and Other Segment includes consolidation eliminations of revenues and cost of energy between business segments, primarily related to TNMP’s sale of transmission to First Choice. Corporate and Other also includes equity in Optim Energy’s results of operations, which are further explained below.

Other operating expenses increased in the three months ended March 31, 2010 compared to 2009 primarily due to credits of $2.4 million related to elimination of operating lease expense paid by PNM to PNMR related to a portion of PVNGS Unit 2, which was transferred to PNM in July 2009. This amount is offset in PNM Electric.

Depreciation expense decreased $0.5 million in the three months ended March 31, 2010 compared to 2009 related to a decrease in asset base, primarily resulting from the transfer of a portion of PVNGS Unit 2 to PNM in July 2009.

Other income and deductions decreased in 2010 compared to 2009 primarily due to a $15.0 million fee received upon termination of the CRHC acquisition agreement and a gain of $7.5 million on the re-acquisition of $157.4 million of PNMR’s 9.25% senior unsecured notes, both of which occurred in 2009.

Interest charges decreased in 2010 compared to 2009 primarily due to lower long-term borrowings due to the re-acquisition of $157.4 million of PNMR’s 9.25% senior unsecured notes, which occurred in February 2009, and lower short-term borrowings.

Optim Energy

The table below summarizes the operating results for Optim Energy:

	Three Months Ended March 31,
	2010			2009			Change
				(In millions)

Total operating revenues	$	105.6		$	78.4		$	27.2
Cost of energy		77.3			45.2			32.1
Gross margin		28.3			33.2			(4.9	)
Operating expenses		19.5			19.9			(0.4	)
Depreciation and amortization		12.1			7.7			4.4
Operating income (loss)		(3.3	)		5.7			(9.0	)
Other income (deductions)		0.1			0.1			0.0
Interest charges		(4.7	)		(2.5	)		(2.2	)
Earnings (loss) before income taxes		(7.9	)		3.3			(11.2	)
Income (tax) benefit on margin		-			(0.2	)		(0.2	)
Net earnings (loss)	$	(8.0	)	$	3.1		$	(11.1	)

50 percent of net earnings (loss)	$	(4.0	)	$	1.6		$	( 5.6	)
Plus amortization of basis difference in Optim Energy		(0.4	)		(0.2	)		(0.2	)
PNMR equity in net earnings (loss) of Optim Energy	$	(4.4	)	$	1.4		$	(5.8	)

Optim Energy’s current strategy and near-term focus is on utilizing cash flow from operations to reduce debt and optimizing its generation assets as a stand-alone independent power producer. The goal is to position Optim Energy to optimize its performance in the current market with expectation of being able to take advantage of any economic recovery in the power and gas market over the next several years.

Optim Energy’s management evaluates the results of operations on an on-going earnings before interest, income taxes, depreciation, amortization, mark-to-market, and certain other items (“On-going EBITDA”) basis. Altura (Twin Oaks), Altura Cogen, and Cedar Bayou 4 generating stations comprise Optim Energy’s core business. Revenue related to power sales and purchases is included net in operating revenues. Costs related to fuel purchases and sales are recorded net in cost of sales.

The addition of Cedar Bayou 4 increased generation from 1,157 GWh for the three months ended March 31, 2009 to 1,616 GWh in 2010. Commercial optimization of generation, increased wind generation in Texas, and well-positioned assets resulted in an increase in ancillary revenues of $4.3 million in 2010 compared to 2009. This increase was partially offset by excess emission sales of $1.8 million realized in 2009 that did not recur in 2010. In addition, Optim Energy has a long-term capacity contract that triggers higher rates when sales volumes decline. In the three months ended March 31, 2009, Optim Energy recognized revenue of $1.5 million under this provision. In 2010, the customer's industrial production increased and these payments have returned to their lower price levels.

On-going EBITDA excludes purchase accounting amortization included in gross margin related to out of market contracts and emission allowances that were recorded at the acquisition of Altura and Altura Cogen. Amortization related to out of market contracts decreased total operating revenues $4.0 million in 2010 and $3.1 million in 2009. Amortization for out of market contracts will continue through the expiration of each contract, which is 2010 for Altura and 2021 for Altura Cogen. In addition, 2010 and 2009 cost of energy each includes $1.3 million of amortization related to emission allowances acquired in the acquisitions. The amortizations for emission allowances are recorded as the allowances are used in plant operations, sold or expire.

On-going EBITDA excludes interest expense and depreciation. Construction of Cedar Bayou 4 was completed in June 2009. Optim Energy capitalized $1.6 million of interest in 2009 related to this development, resulting in a 2010 increase in interest expense. Depreciation of Cedar Bayou 4 began after completion and amounted to $1.9 million in the three months ended March 31, 2010. Other asset additions in 2009 and shortened asset lives resulted in the additional depreciation increases.

Optim Energy has a hedging program that covers a multi-year period. The level of hedging at any given time varies depending on current market conditions and other factors. Economic hedges that do not qualify for or are not designated as cash flow hedges or normal purchases/sales are derivative instruments that are required to be marked to market. On-going EBITDA excludes the forward mark-to-market gains of $4.3 million for 2010 and $9.4 for 2009.

LCC is Optim Energy’s counterparty in several agreements for power and steam sales. In addition, LCC leases Optim Energy the land for the Altura Cogen facility and provides other services, including water, to that facility. On January 6, 2009, LCC filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. The pre-petition amount due from LCC is immaterial and was fully reserved as of December 31, 2008. LCC has continued to perform under the existing contracts since the filing. LCC’s bankruptcy plan was confirmed by the bankruptcy court on April 23, 2010. LCC has filed documents with the bankruptcy court indicating its intent to assume its contracts with Altura Cogen. As part of this process, LCC is required to cure pre-petition defaults under its contracts with Altura Cogen. Altura Cogen and LCC are negotiating the terms of a stipulation to cure these defaults.

The contribution of Altura created a basis difference between PNMR’s recorded investment in Optim Energy and 50 percent of Optim Energy’s equity. The PNMR net earnings impact does not equal 50 percent of the Optim Energy amortization because of this basis difference. While the portion of the basis difference related to contract amortization will only continue through 2010, other basis differences, including a difference related to emission allowances, will continue to exist through the life of the Altura plant. The basis difference adjustment detailed above relates primarily to contract amortization with insignificant offsets related to the other minor basis difference components.

LIQUIDITY AND CAPITAL RESOURCES

Statements of Cash Flows

The changes in PNMR’s cash flows for the three months ended March 31, 2010 compared to 2009 are summarized as follows:

	Three Months Ended March 31,
	2010				2009			Change
				(In millions)
Net cash flows from:
Operating activities	$	(13.3	)		$	(15.3	)	$	2.0
Investing activities		(54.1	)			560.7			(614.8	)
Financing activities		81.7				(615.6	)		697.3
Net change in cash and cash equivalents	$	14.3			$	(70.2	)	$	84.5

The change in PNMR’s cash flows from operating activities reflects improved results of operations at PNM and TNMP in 2010, primarily due to the impact of rate increases. In 2010, the operating results of First Choice were negatively impacted by $27.8 million of mark-to-market losses on derivative contracts, which do not impact cash flows from operations. Lower interest payments resulting from reduced debt as discussed below also had a favorable impact. Increases were offset by increased collateral requirements at PNM and First Choice in 2010.

The changes in cash flows from investing activities relate primarily to the proceeds from the sale of PNM Gas in 2009. Reduced construction expenditures in 2010, mostly at PNM, were partially offset by increased payments for rights of way renewals.

The changes in cash flows from financing activities relate primarily to the use of the proceeds from the sale of PNM Gas to retire short-term borrowings at PNM and PNMR, as well as the retirement of long-term borrowings at PNMR in 2009. At TNMP, the retirement of both short-term and long-term borrowings was financed by new long-term borrowings in 2009. In 2010, short-term borrowings were used to fund continuing construction expenditures.

Financing Activities

See Note 7 for information concerning the Company’s financing activities during the three months ended March 31, 2010. Additional information on the Company’s financing activities is contained in Note 6 of Notes to Consolidated Financial Statements in the 2009 Annual Reports on Form 10-K.

Capital Requirements

Total capital requirements consist of construction expenditures and cash dividend requirements for both common and preferred stock. PNMR’s Series A convertible preferred stock is entitled to receive dividends equivalent to any dividends paid on PNMR common stock as if the preferred stock had been converted into common stock. The main focus of PNMR’s current construction program is upgrading generation resources, constructing renewable energy resources to be owned by PNM, upgrading and expanding the electric transmission and distribution systems, and purchasing nuclear fuel. Projections, including amounts expended through March 31, 2010, for total capital requirements for 2010 are $331.3 million, including construction expenditures of $285.1 million. Total capital requirements for the years 2010-2014 are projected to be $1,770.4 million, including construction expenditures of $1,509.8 million. These amounts do not include forecasted construction expenditures of Optim Energy. These estimates are under continuing review and subject to on-going adjustment, as well as to Board review and approval. TNMP is planning to undertake a project to install an advanced metering system for customers it serves. This would entail an investment of approximately $70 million, which is not included in the above numbers and has not yet been approved by the Board. TNMP will not commit to this project before the method of recovery of the investment is authorized by the PUCT. TNMP anticipates making a filing with the PUCT in the second quarter of 2010 to request this authorization. During the first three months of 2010, the Company utilized its liquidity arrangements, to meet its capital requirements, including construction expenditures.

In April 2010, PNMR and ECJV each made an equity contribution to Optim Energy of $15.0 million in cash. PNMR and ECJV also agreed to make additional cash contributions during 2010 that would aggregate approximately $5.0 million from each owner. Optim Energy used the equity contributions to reduce amounts outstanding under its bank financing arrangement and will also use the additional contributions to reduce debt . If Optim Energy undertakes additional projects, which require funds that would exceed the capacity of its current credit facility and Optim Energy is unable to obtain additional financing capabilities, PNMR and ECJV may be asked to provide additional funding, but such funding would be at the option of PNMR and ECJV and no assurance can be given that such funding will be available to Optim Energy. PNMR is unable to predict if additional funding will be required or, if required, the amount or timing of additional funds that would be provided to Optim Energy.

Liquidity

PNMR’s liquidity arrangements include the PNMR Facility and the PNM Facility both of which primarily expire in 2012 and the TNMP Revolving Credit Facility, which expires in April 2011. These facilities provide short-term borrowing capacity and also allow letters of credit to be issued, which reduce the available capacity under the facilities. These credit facilities will need to be renegotiated or replaced prior to their expirations in order to provide sufficient liquidity to finance operations and construction expenditures. The availability of such credit facilities, including their amounts for borrowing thereunder and their terms and conditions, will depend on the credit markets at that time, as well as the Company’s credit ratings and operating results. Both PNMR and PNM also have lines of credit with local financial institutions. As of April 30, 2010, the Company had short-term debt outstanding of $309.0 million at an average interest rate of 1.10%.

Although accessing the capital markets at the current time could be difficult as well as costly, 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. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under its current and future liquidity arrangements. However, if market difficulties experienced during the recession resurge or worsen, the Company may not be able to access the capital markets or renew credit facilities when they expire. In such event, the Company would seek to improve cash flows by reducing capital expenditures and PNM would consider seeking authorization for the issuance of first mortgage bonds in order to improve access to the capital markets, as well as any other alternatives that may remedy the situation at that time.

In addition to its 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 2010-2014 period.

The Company’s ability, if required, to access the credit and capital markets at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, its results of operations, its credit ratings, its ability to obtain required regulatory approvals and conditions in the financial markets. The credit ratings for PNMR, PNM, and TNMP are set forth under the heading Liquidity in the MD&A contained in the 2009 Annual Reports on Form 10-K. On March 9, 2010, Moody’s revised its outlook to stable from negative for PNMR, PNM, and TNMP. In addition, Moody's upgraded the senior secured obligations of TNMP to Baa1 from Baa2. All other credit ratings remain unchanged.

A summary of liquidity arrangements as of April 30, 2010 is as follows:

	PNMR		PNM		TNMP		PNMR
	Separate		Separate		Separate		Consolidated
			(In millions)
Financing Capacity:
Revolving credit facility	$	568.0	$	400.0	$	75.0	$	1,043.0
Local lines of credit		5.0		5.0		-		10.0
Total financing capacity	$	573.0	$	405.0	$	75.0	$	1,053.0

Amounts outstanding as of April 30, 2010:
Revolving credit facility	$	101.0	$	208.0	$	-	$	309.0
Local lines of credit		-		-		-		-
Total short-term debt outstanding		101.0		208.0		-		309.0

Letters of credit		73.1		13.3		0.3		86.7

Total short–term debt and letters of credit	$	174.1	$	221.3	$	0.3	$	395.7

Remaining availability as of April 30, 2010	$	398.9	$	183.7	$	74.7	$	657.3
Invested cash as of April 30, 2010	$	15.4	$	9.3	$	-	$	24.7

The above table excludes intercompany debt. The remaining availability under the revolving credit facilities varies based on a number of factors, including the timing of collections of accounts receivables and payments for construction and operating expenditures. LBB was a lender under the PNMR Facility and the PNM Facility. LBH, the parent of LBB, has filed for bankruptcy protection. Subsequent to the bankruptcy filing by LBH, LBB declined to fund a borrowing request under the PNMR Facility. In March 2010, the PNMR Facility was amended to remove LBB as a lender and reduce the total capacity under the PNMR Facility from $600.0 million to $568.0 million. In addition to the reduction in the PNMR Facility related to LBB, the PNMR Facility and the PNM Facility will reduce by $26.0 million and $14.0 million in 2010 and an additional $25.0 million and $18.0 million in 2011 according to their terms. The Company does not believe amending the PNMR Facility to remove LBB or the scheduled reduction in the facilities will have a significant impact on PNMR’s and PNM’s liquidity.

For offerings of debt securities registered with the SEC, PNMR has an effective shelf registration statement expiring in April 2011. This shelf registration statement has unlimited availability and can be amended to include additional securities, subject to certain restrictions and limitations. PNMR can offer new shares of PNMR common stock through the PNM Resources Direct Plan under a separate SEC shelf registration statement that expires in August 2012. In April 2008, PNM filed a new shelf registration statement for the issuance of up to $750.0 million of senior unsecured notes that expires in April 2011. As of April 30, 2010, PNM had $600.0 million of remaining unissued securities registered under this and a prior shelf registration statement.

As discussed above and in Note 7, disruption in the credit markets has had a significant adverse impact on a number of financial institutions and several of the financial institutions that the Company deals with have been impacted. However, at this point in time, the Company’s liquidity has not been materially impacted and management does not expect that it will be materially impacted in the near-future.

Off-Balance Sheet Arrangements

PNMR’s off-balance sheet arrangements include PNM’s operating lease obligations for PVNGS Units 1 and 2, the EIP transmission line, and the entire output of Delta, a gas-fired generating plant. These arrangements help ensure PNM the availability of lower-cost generation needed to serve customers. See MD&A – Off-Balance Sheet Arrangements and Note 7 of Notes to Consolidated Financial Statements in the 2009 Annual Report on Form 10-K.

Commitments and Contractual Obligations

PNMR, PNM, and TNMP have contractual obligations for long-term debt, operating leases, purchase obligations, and certain other long-term liabilities. See MD&A – Commitments and Contractual Obligations in the 2009 Annual Reports on Form 10-K.

Contingent Provisions of Certain Obligations

As discussed in the 2009 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. The contingent provisions 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 and the requirement to provide security under certain contractual agreements. The Company believes its financing arrangements are sufficient to meet the requirements of the contingent provisions.

Capital Structure

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

	March 31,			December 31,
	2010			2009
PNMR
PNMR common stockholders’ equity		49.3	%		49.6	%
Convertible preferred stock		3.0	%		3.0	%
Preferred stock of subsidiary		0.3	%		0.3	%
Long-term debt		47.4	%		47.1	%
Total capitalization		100.0	%		100.0	%

PNM
PNM common stockholder’s equity	52.0	%	51.9	%
Preferred stock	0.5	%	0.5	%
Long-term debt	47.5	%	47.6	%
Total capitalization	100.0	%	100.0	%

TNMP
Common stockholder's equity	59.4	%	59.3	%
Long-term debt	40.6	%	40.7	%
Total capitalization	100.0	%	100.0	%

OTHER ISSUES FACING THE COMPANY

Climate Change Issues

Background

In 2009, PNMR’s interests in generating plants, through PNM and Optim Energy, emitted approximately 9.6 million metric tons of carbon dioxide, the vast majority of its GHG. By comparison, the total GHG in the United States in 2008, the latest year for which the EPA has compiled this data, were approximately 7.0 billion metric tons, of which approximately 5.9 billion metric tons were carbon dioxide. Electricity generation accounted for approximately 2.4 billion metric tons of the carbon dioxide emissions.

PNM has several programs underway to mitigate its GHG, and thereby to reduce its climate change risk. See Note 10. On January 25, 2010, PNM filed with the NMPRC its revised renewable procurement plan that, if approved, will result in up to 80 MWs of new solar generation on PNM’s system by the end of 2013. In 2008, PNM filed requests for approval to implement additional electric energy efficiency and load management programs with the NMPRC, which approved the programs in May 2009. Over the next 19 years, PNM projects the expanded energy efficiency and load management programs will provide the equivalent of approximately 15,000 GWh of electricity, which will avoid at least 1.8 million metric tons of CO 2 based upon projected emissions from PNM’s system-wide portfolio with and without these programs. These estimates are subject to change given that it is difficult to accurately estimate avoidance because of the many variables that impact it, including changes in demand for electricity.

The Board is updated by management and regularly considers the issues around climate change, our GHG and potential financial consequences that might result from potential federal and/or state regulation of GHG. In particular, management periodically reports to the Board on all of the matters discussed in this section. In December 2008, the Board established a new stand-alone committee, the Public Policy and Sustainability Committee. This committee monitors Company practices and procedures to assess the sustainability impacts of our operations and products on the environment. This committee also has responsibility to review the Company’s environmental management systems, monitor the implementation of the Company’s corporate environmental policy, monitor the promotion of energy efficiency, and the use of renewable energy resources. The committee reports to the Board on a periodic basis regarding the Company’s activities and initiatives in these areas.

EPA Regulation

In April 2007, the U.S. Supreme Court held that the EPA has the authority to regulate GHG under the Clean Air Act. This decision, coupled with an increased focus in the Obama administration and Congress on legislation to address climate change, has heightened the importance of this issue for the energy industry. Although there continues to be debate over the details and best design for state and federal programs, increased state and federal legislative and regulatory activities calling for regulation of GHG indicate that climate change protection legislation and regulation are likely in the future.

In July 2008, the EPA published the Greenhouse Gas Advanced Notice of Proposed Rulemaking. The notice identified, but did not choose among, options for GHG regulation and requested comments on the options presented. Absent Congressional action, in due course the Company expects the EPA to adopt regulations relating to GHG.

In December 2009, the EPA released its final endangerment finding stating that the atmospheric concentrations of six key greenhouse gases (carbon dioxide, methane, nitrous oxides, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride) endanger the public health and welfare of current and future generations. The finding does not by itself impose any requirements on producers of GHG, but the finding does set the groundwork for the EPA to regulate GHG from new and existing stationary sources such as power plants and for new motor vehicles. The EPA proposed several rules regulating GHG in anticipation of the final endangerment finding. In September 2009, the EPA proposed GHG motor vehicle standards. The final standards were issued on April 1, 2010. Although promulgation of the motor vehicle standards triggers the applicability of PSD and operating permit (“Title V”) requirements for stationary sources that emit GHG, EPA concluded, in their reconsideration of when GHG regulation under the PSD program will commence, that PSD program requirements will apply to GHG upon the date the motor vehicle standards actually take effect. EPA stated those standards will take effect when the 2012 model year begins which is no earlier than January 2, 2011. The reconsideration did not specify which sources

would be regulated in January 2011. This same date applies to operating permits. With respect to PSD and operating permit requirements, the EPA proposed a rule (known as the “tailoring rule”) that would limit applicability to large facilities emitting over 25,000 metric tons of GHG per year. The proposed rule would require these existing large facilities that undertake a project that results in a significant emissions increase to obtain air permits that demonstrate they are using the best available control technology (“BACT”) to minimize GHG. Each of the Company’s fossil-fueled electric generating plants emits over 25,000 metric tons of GHG per year. The final version of the EPA’s tailoring rule has not yet been promulgated.

EPA regulation of GHG from large stationary sources will impact PNM’s operations due to the Company’s reliance on fossil-fueled electric generation. The impact to PNM is unknown because the regulatory requirements, including what is considered BACT, are not yet defined but could involve investments in efficiency improvements and/or control technologies at the fossil-fueled generating plants.

Federal Legislation

In addition, several legislative initiatives are under consideration in Congress that would regulate GHG. These initiatives range from general limitations on GHG to the imposition of a so-called “cap and trade” system to the imposition of a tariff on GHG. It is unclear whether or when legislation will be passed, although the Obama administration and several leading members of Congress continue to express their intent to pass legislation.

In June 2009, the U.S. House of Representatives passed H.R. 2454, the American Clean Energy and Security Act of 2009. This bill, commonly referred to as the Waxman-Markey Bill, if ultimately passed into law, would establish an economy-wide program, with cap and trade as its cornerstone, regulating GHG. The bill defines specific emissions reductions requirements and timelines, provides for the allocation of free allowances to electric utilities in the early years of the program to help mitigate cost impacts to ratepayers and allows for compliance flexibility through cost control mechanisms including the establishment of an offset program that will further help mitigate costs to consumers.

On November 5, 2009, the Senate Environment and Public Works Committee reported the Clean Energy Jobs and American Power Act (“S. 1733”) out of committee. While the bill is broadly similar to the climate change framework in the Waxman-Markey Bill, there are significant differences, including a more aggressive GHG reduction target for 2020. It appears unlikely that S. 1733 has the bipartisan support required to pass the Senate. Consequently, since November 2009, Senator Kerry (D, MA), an original cosponsor of S. 1733, Senator Graham (R, SC) and Senator Lieberman (I, CN) have been working together to develop climate change legislation that could attract the bipartisan support necessary for enactment.

The Company has assessed, and continues to assess, the impacts of potential climate change legislation or regulation on its business. This assessment is preliminary, and changes in the legislative or regulatory process could impact the assessment significantly. The Company’s assessment includes assumptions regarding the specific GHG limits, the timing of implementation of these limits, the level of emissions allowances allocated and the level that must be purchased, the development of technologies for renewable energy and to reduce emissions, the cost of emissions allowances, the degree to which offsets may be used for compliance, and provisions for cost containment. Moreover, the assessment assumes various market reactions such as with respect to 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 would likely, among other things, result in significant compliance costs, including significant capital expenditures by the Company, and could jeopardize the economic viability of certain generating facilities. For example, see the discussion of Four Corners in Note 9 under the caption The Clean Air Act – Regional Haze. In turn, these consequences would lead to increased costs to customers and could 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 demand for electricity. The Company’s assessment process is ongoing but too preliminary and speculative at this time for the meaningful prediction of financial impact.

USCAP

In 2006, the Company became a founding member of the United States Climate Action Partnership (“USCAP”), a coalition currently consisting of 35 businesses and national environmental organizations calling on the federal government to enact national legislation to reduce GHG at the earliest practicable date. USCAP released

A Call To Action , a set of principles and recommendations outlining a policy framework for federal climate protection legislation in January 2007, and released its Blueprint for Legislative Action to the U.S. Congress and the Obama Administration in January 2009. It is the Company’s longstanding position that a mandatory, economy-wide, market-driven approach that includes a cap and trade program, combined with other complementary state and federal policies, is the most cost effective and environmentally efficient means of addressing GHG reductions. In addition, by eliminating the regulatory uncertainty of GHG regulation, a properly designed federal program could result in clean energy investment and allow utilities to make informed long-term investments. The Company intends to continue working with USCAP, government agencies, and Congress to advocate for federal action to address this challenging environmental issue that is closely linked with the U.S. economy, energy supply, and energy security. The basic framework of the part of the Waxman-Markey Bill described above that addresses global warming is consistent with the framework proposed by USCAP in its Blueprint for Legislative Action .

State and Regional Activity

Pursuant to New Mexico law, each utility must submit an integrated resource plan 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 integrated resource plan 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 PNM’s customers. The NMPRC issued an order in June 2007, requiring that New Mexico utilities factor a standardized cost of carbon emissions into their integrated resource plans 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 in 2010 and thereafter. 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. PNM is required, however, to use these prices for purposes of its integrated resource plan, and the prices may not reflect the costs that it ultimately will incur. The public involvement phase of PNM’s next integrated resource plan will begin by July 2010.

In December 2008, New Energy Economy (“NEE”), a non-profit environmental advocacy organization, petitioned the New Mexico Environmental Improvement Board (“EIB”) to amend existing regulations and adopt new regulations that would reduce GHG from sources regulated by the State of New Mexico. The EIB ordered legal briefs to be filed on the issue of the EIB’s authority to regulate GHG. After review of the briefs and a hearing in April 2009, the EIB decided it does have authority to regulate GHG. On January 13, 2010, PNM along with a diverse group of New Mexico businesses, legislators, and agriculture interests filed a lawsuit in state court requesting a preliminary and permanent injunction enjoining the EIB from conducting further proceedings on the NEE petition based on a challenge of the EIB’s authority to regulate GHG as proposed in the NEE petition. On April 13, 2010, the state court granted the preliminary injunction requested in the lawsuit, prohibiting the EIB from conducting further proceedings on the NEE petition pending a final ruling on the question of the EIB’s authority to regulate GHG.

Seven western states, including New Mexico, and three Canadian provinces have entered into an accord, called the Western Regional Climate Action Initiative (the “WCI”), to reduce GHG from automobiles and certain industries, including utilities. The WCI released design recommendations for elements of a regional cap and trade program in September 2008, and has created several subcommittees to develop detailed implementation recommendations. The subcommittees are slated to complete their work in 2010. Under the WCI recommendations, GHG from the electricity sector and fossil fuel consumption of the industrial and commercial sectors will be capped at then current levels and subject to regulation starting in 2012. Over time, producers will be required to reduce their GHG. Implementation of the design elements for GHG reductions will fall to each state and province. In New Mexico, the Company believes this will require new legislation and rulemaking.

In February 2009, a bill was introduced in the New Mexico legislature proposing to require the implementation by EIB of a cap and trade system designed to reduce GHG. This legislation died in committee during the session. The New Mexico House of Representatives did pass a memorial, which requests the New Mexico Legislative Council to direct the appropriate committee to study the WCI final design recommendations as well as federal proposals relating to reducing GHG. The memorial is a study of impacts and not a regulation. The memorial further states that the committee is requested to report its findings and recommendations to the New Mexico legislature by December 2010.

In January 2010, a similar bill was introduced in the New Mexico House of Representatives that would have allowed EIB to adopt rules for implementing particular portions of WCI, including rules of early reduction allowances, offset allowances and mandatory reporting of GHG for persons importing electricity or heating or transportation fuels. The bill was tabled in committee where it died. In March 2010, the NMED announced a process that will result in NMED requesting that the EIB adopt rules required to implement a WCI cap and trade program. This proposal faces the same question of the EIB’s authority to regulate GHG that will be addressed in the NEE lawsuit. Based on the court’s ruling in the NEE case and the inability to pass a state or regional cap and trade program through the state legislature, the Company does not believe that state regulation of GHG is likely at this time and therefore anticipates no impact from the proposed New Mexico legislation and regulations.

Impact of International Accords, Indirect Consequences, and Physical Impacts

Approximately 82.8% of PNM’s owned and leased generating capacity consists of coal or gas-fired generation that produces GHG, all of which is located within the United States. The company does not anticipate any direct impact from any near term international accords. All of Optim Energy’s owned generation produces GHG and is located within the United States. Based on current forecasts, the Company does not expect its output of GHG to increase significantly in the near-term. Many factors affect the amount of GHG, including plant performance. For example, if PVNGS experienced prolonged outages, it may require PNM to utilize other power supply resources such as gas-fired generation, which could increase GHG. Because of our dependence on fossil-fueled generation, any legislation that imposes a limit or cost on GHG will impact the cost at which we produce electricity. While PNM expects to be entitled to recover that cost through rates, the timing and outcome of proceedings for cost recovery is uncertain. In addition, to the extent that we recover any additional costs through rates, our customers may reduce their demand, relocate facilities to other areas with lower energy costs or take other actions that ultimately will adversely impact us.

Given the geographic location of our facilities and customers, we generally have not been exposed to the extreme weather events and other physical impacts commonly attributed to climate change, with the possible exception of drought conditions periodically, and we generally do not expect physical changes to be of material consequence to us in the near-term. Drought conditions in northwestern New Mexico could impact the availability of water for cooling coal plants. Water shortage sharing agreements have been in place since 2003, although no shortage has been declared due to sufficient snow pack in the San Juan Basin. PNM also has a supplemental water contract in place with the Jicarilla Tribe to help address any water shortages from primary sources. The contract expires December 31, 2016.

Other Matters

See Notes 9 and 10 herein and Notes 16, 17 and 18 in the 2009 Annual Reports on Form 10-K for a discussion of commitments and contingencies, rate and regulatory matters and environmental issues facing the Company.

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 March 31, 2010, there have been no significant changes with regard to the critical accounting policies disclosed in PNMR’s, PNM’s, and TNMP’s 2009 Annual Reports on Forms 10-K. The policies disclosed included unbilled revenues, regulatory accounting, impairments, decommissioning costs, derivatives, pension and other postretirement benefits, accounting for contingencies, income taxes, and market risk.

MD&A FOR PNM

RESULTS OF OPERATIONS

PNM’s continuing operations are presented in the PNM Electric segment, which is identical to the segment presented above in Results of Operations for PNMR. PNM’s discontinued operations are presented in the PNM Gas segment, which is identical to the total earnings from discontinued operations, net of income taxes, shown on the Condensed Consolidated Statements of Earnings for both PNM and PNMR. See Note 14.

MD&A FOR TNMP

RESULTS OF OPERATIONS

TNMP operates in only one reportable segment, TNMP Electric, 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 and PNMR, PNM, and TNMP assume no obligation to update this information.

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 flow 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:

●

Conditions affecting the Company’s ability to access the financial markets and negotiate new credit facilities for those expiring in 2011 and 2012, or Optim Energy’s access to additional debt financing following the utilization of its existing credit facility, including actions by ratings agencies affecting the Company’s credit ratings,

●	The recession, its consequent extreme disruption in the credit markets, and its impacts on the electricity usage of the Company’s customers,

●	State and federal regulatory and legislative decisions and actions, including appeals of prior regulatory proceedings, and including provisions relating to climate change, reduction of GHG, CCBs, and other power plant emissions,

●

The ability of PNM to meet the renewable energy requirements established by the NMPRC, including the resource diversity requirement, within the specified cost parameters, and the Company’s ability to obtain federal and/or state funding and incentives for the development of alternative or renewable energy,

●	The ability of PNM to successfully utilize a future test year in a rate filing with the NMPRC, including PNM’s ability to accurately forecast operating and capital expenditures and withstand challenges by regulators and intervenors,

●	The performance of generating units, including PVNGS, SJGS, Four Corners, and Optim Energy generating units, and transmission systems,

●	The risk that Optim Energy desires to expand its generation capacity but is unable to identify and implement profitable acquisitions or that PNMR and ECJV will not agree to make additional capital contributions to Optim Energy,

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

●	The impacts of the decline in the values of marketable equity securities on the trust funds maintained to provide nuclear decommissioning funding and pension and other postretirement benefits, including the levels of funding and expense,

●	The ability of First Choice to attract and retain customers and collect amounts billed,

●	Changes in ERCOT protocols,

●	Changes in the cost of power acquired by First Choice,

●	Collections experience,

●	Insurance coverage available for claims made in litigation,

●	Fluctuations in interest rates,

●

Weather,

●	Water supply,

●	Changes in fuel costs,

●	Availability of fuel supplies,

●	Uncertainty regarding the requirements and related costs of decommissioning power plants owned or partially owned by PNM and Optim Energy and coal mines supplying certain PNM power plants, as well as the ability to recover decommissioning costs through charges to customers,

●	The risk that replacement power costs incurred by PNM related to not meeting the specified capacity factor for its generating units under its Emergency FPPAC will not be approved by the NMPRC,

●	The risk that PNM may not be able to renew rights-of-way on Native American lands or that the costs of rights-of-way are not allowed to be recovered through rates charged to customers,

●	The effectiveness of risk management and commodity risk transactions,

●	Seasonality and other changes in supply and demand in the market for electric power,

●	The impact of mandatory energy efficiency measures on customer energy usage,

●	Variability of wholesale power prices and natural gas prices,

●	Volatility and liquidity in the wholesale power markets and the natural gas markets,

●	Uncertainty regarding the ongoing validity of government programs for emission allowances,

●	The risk that the resolution of the bankruptcy of LCC results in significant adverse impacts on the operations of the Altura Cogen facility and Optim Energy,

●	Changes in the competitive environment in the electric industry,

●

The risk that the Company and Optim Energy may have to commit to substantial capital investments and additional operating costs to comply with new environmental requirements including possible future requirements to address concerns about global climate change, and the resultant impacts on the operations and economic viability of generating plants in which PNM and Optim Energy have interests,

●	The risks associated with completion of generation, transmission, distribution, and other projects, including construction delays and unanticipated cost overruns,

●	Uncertainty surrounding the status of PNM’s participation in jointly-owned projects resulting from the scheduled expiration of the operational documents for the projects beginning in 2015 and potential changes in the objectives of the participants in the projects,

●	The outcome of legal proceedings,

●	Changes in applicable accounting principles, and

●	The performance of state, regional, and national economies.

Any material changes to risk factors occurring after the filing of PNMR’s, PNM’s, or TNMP’s 2009 Annual Report 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.”

SECURITIES ACT DISCLAIMER

Certain securities described 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.

WEB SITE

The PNMR website, www.pnmresources.com , is an important source of Company information and PNMR encourages investors, analysts and other interested parties to visit the website frequently. PNMR keeps the site updated and routinely posts new information or updated information for public consumption. PNMR encourages analysts, investors and other interested parties to register on the website to automatically receive Company financial information by email. Once registered, participants can choose from a menu to automatically receive requested information, including news releases, notices of webcasts and filings with the SEC. Participants can unsubscribe at any time and will not receive information that was not requested. The contents of the website are not part of this Form 10-Q.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PNMR controls the scope of its various forms of risk through a comprehensive set of policies and procedures and oversight by senior level management and the Board. The Board’s Finance Committee sets the risk limit parameters. The RMC, comprised of corporate and business segment officers, oversees all of the risk management activities, which include commodity risk, credit risk, interest rate risk, and business risk. The RMC has oversight for the ongoing evaluation of the adequacy of the risk control organization and policies. PNMR has risk control organizations, which are 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 specifically include: establishment of policies regarding risk exposure levels and activities in each of the business segments; authority to approve the types of derivatives entered into; authority to establish a general policy regarding counterparty exposure and limits; authorization and delegation of transaction limits; review and approval of controls and procedures for derivative activities; review and approval of models and assumptions used to calculate mark-to-market and market risk exposure; authority to approve and open brokerage and counterparty accounts for derivatives; review of hedging and risk activities; the extent and type of reporting to be performed for monitoring of limits and positions; and quarterly reporting to the Audit and Finance Committees on these activities. The RMC also proposes risk limits, such as VaR and GEaR, to the Finance Committee for its approval.

It is the responsibility of each business segment to create its own control procedures and policies within the parameters established by the Corporate Financial Risk Management Policy, approved by the Finance Committee. The RMC reviews and approves these policies, which are created with the assistance of the Risk Management Department and the Vice President and Treasurer. Each business segment’s policies address the following controls: authorized instruments and markets; authorized personnel; policies on segregation of duties; policies on mark-to-market accounting; responsibilities for deal capture; confirmation responsibilities; responsibilities for reporting results; statement on the role of derivative transactions; and limits on individual transaction size (nominal value).

To the extent an open position exists, fluctuating commodity prices 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.

Information concerning accounting for derivatives and the risks associated with commodity contracts is set forth in Note 4. Note 4 also contains a summary of the fair values of mark-to-market energy related derivative contracts included in 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 other than designated cash flow hedges:

	Trading			Economic Hedges			Total
Three Months Ended March 31, 2010	(In thousands)
Sources of fair value gain (loss):
Net fair value at beginning of period	$	1,239		$	2,217		$	3,456
Amount realized on contracts delivered during period		(294	)		771			477
Changes in fair value		3			(33,835	)		(33,832	)
Net change recorded as mark-to-market		(291	)		(33,064	)		(33,355	)
Unearned/prepaid option premiums		-			1,618			1,618
Settlement of de-designated cash flow hedges		-			476			476
Net fair value at end of period	$	948		$	(28,753	)	$	(27,805	)

Three Months Ended March 31, 2009
Sources of fair value gain (loss):
Net fair value at beginning of period	$	2,556		$	(5,422	)	$	(2,866	)
Amount realized on contracts delivered during period		(1,565	)		4,876			3,311
Changes in fair value		(5	)		(10,261	)		(10,266	)
Net change recorded as mark-to-market		(1,570	)		(5,385	)		(6,955	)
Unearned/prepaid option premiums		-			(480	)		(480	)
Net fair value at end of period	$	986		$	(11,287	)	$	(10,301	)

The following table provides the maturity of PNMR’s net assets (liabilities) other than cash flow hedges, giving an indication of when these mark-to-market amounts will settle and generate (use) cash. The following values were determined using broker quotes and option models:

Fair Value of Mark-to-Market Instruments at March 31, 2010

	Less than
	1 year			1-3 Years			4+ Years			Total
				(In thousands)
Trading
Prices actively quoted	$	4,800		$	-		$	-		$	4,800
Prices provided by other external sources		(3,852	)		-			-			(3,852	)
Prices based on models and other valuations		-			-			-			-
		948			-			-			948
Economic hedges
Prices actively quoted		(15,938	)		(5,636	)		-			(21,574	)
Prices provided by other external sources		(4,446	)		(2,540	)		(278	)		(7,264	)
Prices based on models and other valuations		(15	)		100			-			85
		(20,399	)		(8,076	)		(278	)		(28,753	)
Total	$	(19,451	)	$	(8,076	)	$	(278	)	$	(27,805	)

The fair value of PNMR’s commodity derivative instruments designated as cash flow hedging instruments increased $0.3 million and decreased $2.1 million for the three months ended March 31, 2010 and March 31, 2009.

Risk Management Activities

PNM measures the market risk of its long-term contracts and wholesale activities using a VaR calculation to measure price movements. The VaR calculation reports the possible market loss for the respective transactions. This calculation is based on the transaction’s fair market value on the reporting date. Accordingly, the VaR calculation is not a measure of the potential accounting mark-to-market loss. PNM utilizes the Monte Carlo VaR simulation model. The Monte Carlo model utilizes a random generated simulation based on historical volatility to

generate portfolio values. The quantitative risk information, however, is limited by the parameters established in creating the model. 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. The VaR methodology employs the following critical parameters: historical volatility estimates; market values of all contractual commitments; appropriate market-oriented holding periods; and seasonally adjusted and cross-commodity correlation estimates. The VaR calculation considers PNM’s forward positions, if any. PNM uses a holding period of three days as the estimate of the length of time that will be needed to liquidate the positions. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. The two-tailed confidence level established is 95%. For example, if VaR is calculated at $10.0 million, it is estimated that in 950 out of 1,000 market simulations the pre-tax gain or loss in liquidating the portfolio would not exceed $10.0 million in the three days that it would take to liquidate the portfolio.

PNM measures VaR for all transactions that are not directly asset-related and have economic risk. PNM did not have any non-asset backed transactions for the three months ended March 31, 2010. For the three months ended March 31, 2009, the average, high, and low VaR amount for these transactions was less than $0.1 million. The total VaR amount for these transactions at March 31, 2009 was less than $0.1 million.

First Choice measures the market risk of its retail sales commitments and supply sourcing activities using a GEaR calculation to monitor potential risk exposures related to taking contracts to settlement and a VaR calculation to measure short-term market price impacts.

Because of its obligation to serve customers, First Choice must take certain contracts to settlement. Accordingly, a measure that evaluates the settlement of First Choice’s positions against earnings provides management with a useful tool to manage its portfolio. First Choice uses a hold-to-maturity at risk for 12 months calculation for its GEaR measurement. The calculation utilizes the same Monte Carlo simulation approach described above at a 95% confidence level and includes the retail load and supply portfolios. Management believes the GEaR results are a reasonable approximation of the potential variability of earnings against forecasted earnings. The quantitative risk information, however, is limited by the parameters established in creating the model. 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. The GEaR calculation considers First Choice’s forward position for the next twelve months and holds each position to settlement. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. For example, if GEaR is calculated at $10.0 million, it is estimated that in 950 out of 1,000 market scenarios calculated by the model the losses against the Company’s forecasted earnings over the next twelve months would not exceed $10.0 million.

For the three months ended March 31, 2010, the average GEaR amount was $3.1 million, with high and low GEaR amounts for the period of $4.4 million and $1.5 million. The total GEaR amount at March 31, 2010 was $2.7 million. For the three months ended March 31, 2009, the average GEaR amount for these transactions was $7.3 million, with high and low GEaR amounts for the period of $11.4 million and $3.8 million. The total GEaR amount for these transactions at March 31, 2009 was $8.4 million.

First Choice utilizes a short-term VaR measure to manage its market risk. The VaR limit is based on the same total portfolio approach as the GEaR measure; however, the VaR measure is intended to capture the effects of changes in market prices over a 10-day holding period. This holding period is considered appropriate given the nature of First Choice’s supply portfolio and the constraints faced by First Choice in the ERCOT market. The calculation utilizes the same Monte Carlo simulation approach described above at a 95% confidence level. The VaR amount for these transactions was $0.5 million at March 31, 2010. For the three months ended March 31, 2010, the high, low and average VaR amounts were $2.3 million, $0.4 million and $1.5 million. The VaR amount for these transactions was $0.7 million at March 31, 2009. For the three months ended March 31, 2009, the high, low and average VaR amounts were $2.0 million, $0.5 million and $1.0 million.

The Company's risk measures are regularly monitored by the Company's RMC. The RMC has put in place procedures to ensure that increases in risk measures that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures. There were no exceedences of VaR or GEaR limits for the three months ended March 31, 2010 or 2009.

The VaR and GEaR limits 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 conducts counterparty risk analysis across business segments and uses a credit management process to assess the financial conditions of counterparties. Credit exposure is regularly monitored by the RMC. The RMC has put procedures in place to ensure that increases in credit risk that exceed the prescribed limits are reviewed and, if deemed necessary, acted upon to reduce exposures.

The following table provides information related to PNMR’s credit exposure as of March 31, 2010. The table further delineates that exposure by the credit worthiness (credit rating) of the counterparties and provides guidance as to the concentration of credit risk to individual counterparties.

Schedule of Credit Risk Exposure

March 31, 2010

					Net
			Number		Exposure
	(b)		of		of
	Credit		Counter		Counter-
	Risk		-parties		parties
Rating (a)	Exposure		>10%		>10%
	(Dollars in thousands)
External ratings:
Investment grade	$	45,395		3	$	21,423
Non-investment grade		4,797		-		-
Internal ratings:
Investment grade		-		-		-
Non-investment grade		104		-		-
Total	$	50,296			$	21,423

(a)

The Rating included in “Investment Grade” is for counterparties with a minimum S&P rating of BBB- or Moody's rating of Baa3. If the counterparty has provided a guarantee by a higher rated entity (e.g., its parent), determination is based on the rating of its guarantor. 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.

(b)

The Credit Risk Exposure is the gross credit exposure, including long-term contracts (other than full requirements 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 (pursuant to contract terms). Exposures are offset according to legally enforceable netting arrangements but are not reduced by available credit collateral. Credit collateral includes advance payments, cash deposits, letters of credit, and parental guarantees received from counterparties. Amounts are presented before the application of such credit collateral instruments. At March 31, 2010, PNMR held advance payments of $21.1 million and credit collateral of $4.9 million to offset its credit exposure.

The following table provides an indication of the maturity of PNMR’s credit risk by credit ratings of the counterparties.

Maturity of Credit Risk Exposure

March 31, 2010

					Greater
	Less than				than		Total
Rating	2 Years		2-5 Years		5 Years		Exposure
			(In thousands)
External ratings:
Investment grade	$	45,244	$	116	$	35	$	45,395
Non-investment grade		4,573		224		-		4,797
Internal ratings:
Investment grade		-		-		-		-
Non-investment grade		104		-		-		104
Total	$	49,921	$	340	$	35	$	50,296

The Company provides for losses due to market and credit risk. Credit risk for PNMR's largest counterparty as of March 31, 2010 was $8.2 million.

Interest Rate Risk

PNMR has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. The majority of PNMR’s long-term debt is fixed-rate debt and does not expose PNMR’s earnings to a major risk of loss due to adverse changes in market interest rates. However, the fair value of all long-term debt instruments would increase by 2.37%, if interest rates were to decline by 50 basis points from their levels at March 31, 2010. 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. As described in Note 7, TNMP has long-term debt of $50.0 million that bears interest at a variable rate. However, TNMP has also entered into a hedging arrangement that effectively results in this debt bearing interest at a fixed rate, thereby eliminating interest rate risk. In addition, in January 2010 PNM entered into a floating-to-fixed interest rate swap with a notional amount of $100.0 million associated with PNM’s unsecured revolving credit facility. At April 30, 2010, PNMR has $309.0 million of consolidated short-term debt outstanding under its revolving credit facilities and local lines of credit, which allow for a maximum aggregate borrowing capacity of $1,053.0 million. These facilities bear interest at variable rates, which averaged 1.10% of April 30, 2010 borrowings, and the Company is exposed to interest rate risk to the extent of future increases in variable interest rates.

The securities held by PNM in the NDT and in trusts for pension and other post-employment benefits had an estimated fair value of $564.8 million at March 31, 2010, of which 29.5% 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 March 31, 2010, the decrease in the fair value of the fixed-rate securities would be 4.7%, or $7.8 million. The securities held by TNMP in trusts for pension and other post-employment benefits had an estimated fair value of $65.5 million at March 31, 2010, of which 24.7% were fixed-rate debt securities that subject TNMP 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 March 31, 2010, the decrease in the fair value of the fixed-rate securities would be 6.2%, or $1.0 million.

PNM and TNMP do not directly recover or return through rates any losses or gains on the securities in the trusts for nuclear decommissioning or pension and other post-employment benefits. 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 and TNMP are at risk for shortfalls in funding of obligations due to investment losses, including those from the equity market and alternatives investment risks discussed below to the extent not ultimately recovered through rates charged to customers.

Equity Market Risk

The NDT and trusts established for PNM’s pension and post-employment benefits hold certain equity securities at March 31, 2010. These equity securities expose PNM to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 56.8% of the securities held by the various PNM trusts as of March 31, 2010. PNM does not directly recover or earn a return through rates on any losses or gains on these equity securities. The trusts established for TNMP’s pension and post-employment benefits hold certain equity securities. These equity securities expose TNMP to losses in fair value should the market values of the underlying securities decline. Equity securities comprised 55.6% of the securities held by the TNMP trusts as of March 31, 2010. There was a significant decline in the general price levels of marketable equity securities in late 2008 and in early 2009. The impacts of these declines were considered in the funding and expense valuations performed for 2009 and 2010 and resulted in reduced income or increased expense related to the pension plans being recorded and will require increased levels of funding beginning in 2010. See Note 8.

Alternatives Investment Risk

The Company has a target of investing 20% of its pension assets in the alternatives asset class, which amounted to 21.3% as of March 31, 2010. This includes real estate, private equity, and hedge funds. These investments are limited partner structures that are multi-manager multi-strategy funds. This investment approach gives broad diversification and minimizes risk compared to a direct investment in any one component of the funds. The general partner oversees the selection and monitoring of the underlying managers. The Company’s Corporate Investment Committee, assisted by its investment consultant, monitors the performance of the funds and general partner’s investment process. There is risk associated with these funds due to the nature of the strategies and techniques and the use of investments that do not have readily determinable fair value. The valuation of the alternative asset class has also been impacted by the significant decline in the general price levels of marketable equity securities.

ITEM 4. CONTROLS AND PROCEDURES

PNMR

Evaluation of disclosure controls and procedures.

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

Changes in internal controls

There have been no changes in PNMR’s internal control over financial reporting (as such term is defined in Rules13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, PNMR’s internal control over financial reporting.

PNM

Evaluation of disclosure controls and procedures.

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

Changes in internal controls

There have been no changes in PNM’s internal control over financial reporting (as such term is defined in Rules13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, PNM’s internal control over financial reporting.

TNMP

Evaluation of disclosure controls and procedures.

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

Changes in internal controls

There have been no changes in TNMP’s internal control over financial reporting (as such term is defined in Rules13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) during the quarter ended March 31, 2010 that have materially affected, or are reasonably likely to materially affect, TNMP’s internal control over financial reporting.

PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Notes 9 and 10 in the Notes to Condensed Consolidated Financial Statements for information related to the following matters, for PNMR, PNM, and TNMP, incorporated in this item by reference.

●	Navajo Nation Environmental Issues

●	Santa Fe Generating Station

●	Coal Combustion By-Products – Sierra Club Actions

●	Gila River Indian Reservation Superfund Site

●	PVNGS Water Supply Litigation

●	San Juan River Adjudication

●	Western United States Wholesale Power Market

●	Begay v. PNM et al

●	PNM – Emergency FPPAC

●	TNMP – Competitive Transition Charge True-Up Proceeding

●	TNMP – Interest Rate Compliance Tariff

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, 2009.

ITEM 6. EXHIBITS

3.1	PNMR	Articles of Incorporation of PNM Resources, 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 the Company’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 the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

3.4	PNMR	Bylaws of PNM Resources, Inc. with all amendments to and including February 17, 2009 (incorporated by reference to Exhibit 3.1 to PNMR’s Current Report on Form 8-K filed February 20, 2009)

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

3.6	TNMP	Bylaws of TNMP as adopted on August 4, 2005 (incorporated by reference to Exhibit 3.2.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005)

10.1	PNMR	Changes in Director Compensation

10.2	PNMR	Fourth Amendment to Credit Agreement, dated as of March 22, 2010 among PNMR, First Choice Power, L. P., the lenders party thereto and Bank of America, N.A., as administrative agent

10.3	PNMR	2010 Officer Incentive Plan

10.4	PNMR	Form of Performance Restricted Stock Rights Award Agreement for performance-based, time-vested restricted stock rights awards based on adjusted cash earnings granted under the PEP in 2010

10.5	PNMR	Form of Performance Cash Award Agreement for performance cash awards based on adjusted cash earnings granted under the PEP in 2010

10.6	PNM	Municipal Effluent Purchase and Sale Agreement dated April 23, 2010 between City of Phoenix, City of Mesa, City of Tempe, City of Scottsdale, and City of Glendale, Arizona municipal corporations; and Arizona Public Service Company and Salt River Project Agricultural Improvement and Power District, , acting on behalf of themselves and El Paso Electric Company, Southern California Edison Company, Public Service Company of New Mexico, Southern California Public Power Authority, and the Los Angeles Department of Water & Power

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 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

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

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

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

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

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: May 7, 2010	/s/ Thomas G. Sategna
	Thomas G. Sategna
	Vice President and Corporate Controller
	(Officer duly authorized to sign this report)

100

Exhibit 10.1

This exhibit is filed to clarify and restate the exhibit filed as Exhibit 10.1 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2009

Change in Director Compensation

Non-employee directors of PNM Resources, Inc. (the “Company”) receive their annual retainer in the form of cash and stock-based compensation as determined by the Company’s Board of Directors. At the December 2009 Board meeting, the Board approved increasing the 2010 annual retainer for non-employee directors from the 2009 annual retainer reported in the Company’s 2009 Proxy Statement by increasing the amount of time-vested restricted stock rights from 2,500 to 4,000. No other changes were made to the amount of stock options, amount of annual cash retainer, or meeting and chair fees. Thus, the 2010 annual retainer for non-employee directors is as follows:

Annual Retainer :		$35,000 (1), 1,000 stock options* and 4,000 restricted stock rights*

Annual Committee Chair Fee :		$ 5,000 paid in quarterly installments (in addition to meeting attendance fees), except that the Annual Audit and Ethics Committee Chair Fee is $10,000

Attendance Fees : (no attendance fee for teleconference meetings less than 1 hour in duration)		$ 1,750 per Board meeting $ 1,500 per Board Committee meeting

* Stock options and restricted stock rights granted under the Company’s Omnibus Performance Equity Plan (“PEP”) each vest in three equal annual installments beginning on the first anniversary of the grant date. These awards are typically made at the annual meeting of directors, unless the meeting occurs during a black-out period for trading in the Company’s securities as specified in the Company’s Insider Trading Policy. As set forth under the Company’s Stock Option Grant Policy, under those circumstances, the Board will either (a) schedule a special meeting after the expiration of the black-out period, (b) make awards pursuant to a unanimous written consent executed after the expiration of the black-out period, or (c) pre-approve the equity awards with an effective date after the expiration of the black-out period. The date of the awards is the date on which the Board approves the awards, unless (i) the approval date is a non-trading day, in which case the date is the immediately preceding trading date or (ii) in the case of pre-approval during a black-out period, in which case the grant date is the first trading date after the expiration of the black-out period. The exercise price of the stock option is equal to the closing price of the common stock on the New York Stock Exchange on the date of the grant. The PEP prohibits option re-pricing.

Directors are also reimbursed for any Board-related expenses, such as travel expenses incurred to attend Board and Board committee meetings and director educational programs.

(1) Jeffry E. Sterba retired as the Company’s Chief Executive Officer (“CEO”) effective March 1, 2010. While employed as CEO, Mr. Sterba received no additional compensation for serving as a director or as the Chairman of the Board and was only reimbursed for any travel related expenses to Board meetings. As reported in a Current Report on Form 8-K filed February 19, 2010, in February 2010, the Board asked Mr. Sterba to continue to serve as Chairman following his retirement as CEO. In his role as Chairman, Mr. Sterba will, among other things, provide support on strategic and public policy issues to the Company. He also continues to serve as chair of the First Choice Power board of managers and as a PNMR representative on the board of Optim Energy, LLC and as its chair. As compensation, Mr. Sterba receives a separate annual retainer of $250,000, prorated from March 1-December 31, 2010 (in lieu of the $35,000 annual cash retainer received by other non-employee directors). As reported in the Company’s 2010 proxy statement, effective March 1, 2010, Mr. Sterba also receives Board attendance fees and is eligible to receive the annual equity award of 1,000 stock options and 4,000 restricted stock rights typically made at the annual meeting of directors. In addition, Mr. Sterba will be reimbursed for any Board-related expenses, such as travel expenses incurred to attend Board meetings.

Exhibit 10.2

FOURTH AMENDMENT TO CREDIT AGREEMENT

THIS FOURTH AMENDMENT TO CREDIT AGREEMENT (this " Amendment ") is entered into as of March 22, 2010 among PNM RESOURCES, INC., a New Mexico corporation (the " Company "), FIRST CHOICE POWER, L.P., a Texas limited partnership (" FCP ", collectively with the Company, the " Borrowers " and each individually, a " Borrower "), the Lenders party hereto, and BANK OF AMERICA, N.A., 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 Borrowers, the Lenders party thereto and the Administrative Agent are parties to that certain Amended and Restated Credit Agreement, dated as of August 15, 2005 (as amended or modified from time to time, the " Credit Agreement ");

WHEREAS, the Borrowers have requested a non-pro rata reduction in the Revolving Committed Amount under the Credit Agreement as described below; and

WHEREAS, the Lenders are willing to agree to such non-pro rata reduction, 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. Amendment to Credit Agreement .

(a) On the Effective Date (as defined in Section 3 below), the Commitment of Aurora Bank FSB (formerly known as Lehman Brothers Bank, FSB, and hereinafter " Aurora ") under the Credit Agreement, whether used or unused, is irrevocably reduced to zero ($0.00) and, from and after the Effective Date, Aurora shall have no further obligation to fund any amount or extend any credit under the Credit Documents.

(b) On the Effective Date, Aurora shall receive from the Borrowers all outstanding amounts of principal of Revolving Loans then due and owing to Aurora and all accrued interest with respect thereto. Aurora agrees that, upon receipt of the amounts in the preceding sentence, it shall have been paid in full for all Revolving Loans, all interest with respect thereto and all fees owed to it under the Credit Agreement and it shall not be entitled to any other amounts under the Credit Agreement except, if applicable, (i) as set forth in Section 2 below and (ii) any fees provided under Section 3.4 of the Credit Agreement as to which Aurora and the Borrowers have otherwise reached agreement on the Effective Date and that have been communicated in writing to the Administrative Agent.

(c) The Revolving Committed Amount is reduced by the amount of Aurora's Commitment from $600,000,000 to $568,000,000 and the definition of "Revolving Committed

Amount" in Section 1.1 of the Credit Agreement is hereby amended and restated in its entirety to read as follows:

" Revolving Committed Amount " means FIVE HUNDRED SIXTY-EIGHT MILLION DOLLARS ($568,000,000) or such other amount, as it may be reduced from time to time in accordance with Section 2.1(d) or increased pursuant to Section 2.1(f).

(d) Schedule 1.1(a) to the Credit Agreement is amended and restated in its entirety in the form of Exhibit A attached to this Amendment.

2. Surviving Provisions . The Borrowers and Aurora hereby agree that, for any actions taken prior to the Effective Date, Sections 3.15, 11.1(e), 11.5 and 11.9 of the Credit Agreement shall continue in effect for the benefit of Aurora in accordance with the terms thereof.

3. Effectiveness; Conditions Precedent .

This Amendment shall be effective on the date (the " Effective Date ") on which:

(a) the Administrative Agent shall have received copies of this Amendment duly executed by the Borrowers, the Lenders, Aurora and the Administrative Agent; and

(b) Aurora shall have received from the Borrower payment of the amounts described in Section 1(b) above.

4. 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.

5. Authority/Enforceability . Each party hereto 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 such Person and constitutes such Person'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 such Person of this Amendment.

6. Representations and Warranties . Each Borrower represents and warrants to the Lenders that (a) the representations and warranties of such 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, (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 entering into this Amendment.

7. No Conflicts . Neither the execution and delivery of this Amendment, nor the consummation of the transactions contemplated herein, nor performance of and compliance with the terms and provisions hereof by any Borrower will (a) violate, contravene or conflict with any provision of its respective articles or certificate of incorporation, bylaws or other organizational or governing document, (b) violate, contravene or conflict with any law, rule, regulation, order, writ, judgment, injunction, decree or permit applicable to a 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 a Borrower is a party or by which it or its properties may be bound or (d) result in or require the creation of any Lien upon or with respect to a Borrower's properties.

8. 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.

9. 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.

BORROWERS :

PNM RESOURCES, INC. ,

a New Mexico corporation

By: /s/ C.N. Eldred

Name: C.N. Eldred

Title: EVP & CFO

FIRST CHOICE POWER, L.P. ,

a Texas limited partnership

By: First Choice Power GP, LLC, its general partner

By:

Name:

Title:

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

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.

BORROWERS :

PNM RESOURCES, INC. ,

a New Mexico corporation

By:

Name:

Title:

FIRST CHOICE POWER, L.P. ,

a Texas limited partnership

By: First Choice Power GP, LLC, its general partner

By: /s/ Brian Hayduk

Name: Brian Hayduk

Title: President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

ADMINISTRATIVE AGENT :

BANK OF AMERICA, N.A. ,

as Administrative Agent

By: /s/ Maria A. McClain

Name: Maria A. McClain

Title: Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

LENDERS :

BANK OF AMERICA, N.A. ,

as a Lender and L/C Issuer

By: /s/ Patrick N. Martin

Name: Patrick N. Martin

Title: Senior Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

WACHOVIA BANK, NATIONAL ASSOCIATION ,

as a Lender and L/C Issuer

By: /s/ Yann Blindert

Name: Yann Blindert

Title: Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

UNION BANK, N.A.

By: /s/ Efrain Soto

Name: Efrain Soto

Title: Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

JPMORGAN CHASE BANK, N.A.

By: / s/ Helen D. Davis

Name: Helen D. Davis

Title: Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

CITIBANK, N.A.

By: / s/ Todd C. Davis

Name: Todd C. Davis

Title: Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

BANK OF AMERICAN, N.A., successor by merger to MERRILL LYNCH BANK USA

By: /s / Patrick Martin

Name: Patrick Martin

Title: Senior Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

MORGAN STANLEY BANK, N.A.

By: / s/ Melissa James

Name: M elissa James

Title: Authorized Signatory

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

UBS LOAN FINANCE LLC

By: /s / Irja R. Otsa

Name: Irja R. Otsa

Title: A ssociate Director

By: / s/ Mary E. Evans

Name: Mary E. Evans

Title: Associate Director

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

WILLIAM STREET COMMITMENT CORPORATION

By: /s / Andrew Caditz

Name: Andrew Caditz

Title: Authorized Signatory

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH (fka

CREDIT SUISSE, CAYMAN ISLANDS BRANCH)

By: /s / Nupur Kumar

Name: Nupur Kumar

Title: Vice President

By: / s/ Lynne-Marie Paquette

Name: Lynne -Marie Paquette

Title: Associate

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

WELLS FARGO BANK, N.A.

By: /s / Yann Blindert

Name: Yann Blindert

Title: V ice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

US BANK NATIONAL ASSOCIATION

By: /s / Holland H. Williams

Name: Holland H. Williams

Title: Port folio Mgr

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

HSBC BANK USA, NATIONAL ASSOCIATION

By: / s/ James B. Kaiser

Name: James B. Kaiser

Title: Sen ior Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

THE BANK OF NEW YORK MELLON

By: / s/ Mark W. Rogers

Name: Mark W. Rogers

Title: Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

ROYAL BANK OF CANADA

By: /s/ Jay T. Sartain

Name: Jay T. Sartain

Title: Authorized Signatory

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

BANK HAPOALIM BM

By: /s / Helen H. Gateson

Name: Helen H. Gateson

Title: Vice President

By: /s / Frederic S. Becker

Name: Frederic S. Becker

Title: Senior Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

BANK OF ALBUQUERQUE, N.A.

By: / s/ John M. Valentine

Name: John M. Valentine

Title: SVP

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

COMPASS BANK

By: /s/ Ellen Wamser

Name: Ellen Wamser

Title: Vice President

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

SOUTHWEST SECURITIES FSB

By: /s / Michael D. Jarrett

Name: Michael D. Jarrett

Title: Chief Credit Officer

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

Aurora hereby agrees to and acknowledges the terms of this Amendment and agrees and consents to its Commitment under the Credit Agreement being irrevocably terminated in full.

AURORA BANK FSB

By: /s/ Theodore Janulis

Name: Theodore Janulis

Title: Chairman

PNM RESOURCES, INC.

FOURTH AMENDMENT TO CREDIT AGREEMENT

Exhibit A

to Fourth Amendment to Credit Agreement

SCHEDULE 1.1(a)

PRO RATA SHARES

Lender	Commitment	Pro Rata Share
Bank of America, N.A.	$60,000,000	10.563380282%
Wachovia Bank, National Association	$60,000,000	10.563380282%
Union Bank of California, N.A.	$60,000,000	10.563380282%
JPMorgan Chase Bank, N.A.	$42,000,000	7.394366197%
Citibank, N.A.	$42,000,000	7.394366197%
Merrill Lynch Bank USA	$32,000,000	5.633802817%
Morgan Stanley Bank	$32,000,000	5.633802817%
UBS Loan Finance LLC	$27,000,000	4.753521127%
William Street Commitment Corporation	$21,000,000	3.697183099%
Credit Suisse, Cayman Islands Branch	$32,000,000	5.633802817%
Wells Fargo Bank, N.A.	$19,500,000	3.433098592%
U. S. Bank National Association	$25,000,000	4.401408451%
HSBC Bank USA, National Association	$25,000,000	4.401408451%
Mellon Bank, N.A.	$21,000,000	3.697183099%
Royal Bank of Canada	$21,000,000	3.697183099%
Bank Hapoalim BM	$16,000,000	2.816901408%
Bank of Albuquerque, N.A.	$12,500,000	2.200704225%
Compass Bank	$10,000,000	1.760563380%
Southwest Securities Bank	$10,000,000	1.760563380%

Total	$568,000,000	100.000000000%

Exhibit 10.3

PNM RESOURCES, INC.

2010 OFFICER INCENTIVE PLAN

INTRODUCTION

PNM Resources, Inc. (the “Company”) has adopted the PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan (the “PEP”), which was approved by the Company’s shareholders and became effective in May 2009. The Company also has adopted this 2010 Officer Incentive Plan (the “Plan”) for the purpose of providing annual cash-based incentive awards (each an “Award”) to eligible Officers (as defined below). 1 The Awards payable to Officers under the Plan are intended to qualify as Performance Cash Awards granted pursuant to Section 9.4 of the PEP. In the case of Officers who are Covered Employees as defined by the PEP, the portion of the Award that is based on Performance Criteria specified in Section 2.1(dd) of the PEP shall be treated as a separate grant that is intended to qualify as a Performance-Based Performance Cash Award granted pursuant to Section 12 of the PEP.

Capitalized terms used in the Plan and not otherwise defined herein shall have the meanings given to them under the terms of the PEP.

ELIGIBILITY

All Officers of the Company and its Affiliates are eligible to participate in the Plan with the exception of the First Choice Power, L.P. (“FCP”) or Optim Energy, LLC (“Optim”) officers, who may be eligible to participate in other incentive plans. For purposes of the Plan, the term “Officer” means any employee of the Company or any Affiliate (other than FCP or Optim) who has the title of Chief Executive Officer, President, Executive Vice President, Senior Vice President or Vice President and who is in salary grade H18 or higher.

PLAN OBJECTIVES

The Plan is designed to motivate and reward eligible Officers for benefiting the Company’s shareholders by achieving and exceeding the Performance Goals (as defined below) established for such Officers.

PERFORMANCE PERIOD

The period over which the Officer’s performance will be measured for purposes of determining whether Awards are payable under the Plan began on January 1, 2010 and ends on December 31, 2010 (the “Performance Period”). The Board Governance and Human Resources Committee (the “Committee”) of the Company’s Board of Directors (the “Board”), in its sole discretion, reserves the right to adjust, amend or suspend the Plan during the Performance Period.

1 The Plan was originally signed by Alice Cobb, SVP and CAO on March 31, 2010. This version of the Plan represents a conformed version of the Plan document signed on March 31, 2010 which incorporate Ms. Cobb’s handwritten amendments to the original Plan.

AWARD DETERMINATION

Awards are based on the Earnings Per Share (“EPS”) levels set forth in Table 1 below, the weighting between Corporate and Business Area goals as described in Table 2 and Award levels achieved as described in Table 3.

Earnings Per Share

First, for any Awards to be payable to eligible Officers, the Company must achieve the Threshold EPS level set forth in Table 1 below. If the Company does not achieve the Threshold EPS level, no Awards are payable under the Plan to any Officers.

For purposes of the Plan, the Company’s EPS will be the net earnings, excluding non-recurring items that do not factor into ongoing earnings, divided by the average number of common shares of PNM Resources, Inc, common stock used to calculate diluted EPS as reported in the Company’s 10-K filed for 2010. The Committee’s determination of the EPS shall be binding and conclusive.

TABLE 1:

	PNMR EPS
No Award	Less than $0.60
Threshold	Greater than or equal to $0.60 and less than $0.64
Target	Greater than or equal to $0.64 and less than $0.75
Maximum	Greater than or equal to $0.75

If the Threshold, Target or Maximum EPS level is achieved, the aggregate potential Awards payable to the Officers at that level of performance (e.g., the aggregate level of Awards payable at Threshold, Target or Maximum as shown in Table 3 below) will make up the Potential Award Pool. If the actual EPS exceeds the minimum level for that performance level by at least $0.01, but is less than the maximum level for that performance level (e.g., if the actual EPS exceeds $0.60 but is less than $0.64) the Potential Award Pool will be increased by using straight line interpolation between the size of the Potential Award Pool based on the attained level (e.g., Threshold) and the size of the Potential Award Pool at the next higher level (e.g., Target). The Potential Award Pool is capped at the Maximum Award level. The Committee has the discretion to increase the Potential Award Pool by an amount less than amount determined by using straight-line interpolation.

Corporate and Business Area Scorecards

The Corporate Goals Scorecard and Business Area Scorecards with each Performance Measure are defined and maintained by the PNM Resources, Inc. Management Systems Group. The performance of the Chief Executive Officer (“CEO”), Senior Officers (Executive

Vice Presidents and Senior Vice Presidents), and Vice Presidents will be measured against their respective Scorecards based on the weightings set forth in Table 2.

TABLE 2:

Scorecard Results
Scorecard Level	Corporate Weighting	Business Area Weighting
CEO & Senior Officers	100%	0%
Vice Presidents	50%	50%

Performance Award Pools

The Performance Award Pool for each Business Area is the amount that could be paid in the aggregate to the Officers included in that Business Area based on performance alone (i.e. determined without regard to any limitations based on EPS levels set forth in Table 3). The Performance Award Pool for a Business Area will be determined by using the following multi-step process:

a)	Select the Scorecard results from the appropriate Corporate Goal and/or Business Area Scorecards;

b)	Then multiply each result by the appropriate weighting for the Scorecard as set forth in Table 2 above;

c)	Then multiply the total Officer salaries for that Business Area times the Target Award Level as set forth in Table 3 below;

d)	Then multiply the result of each Scorecard (step b) times the result of Officer salaries (step c); and

e)	Sum the results for the Vice President participants.

Award Levels

For purposes of the Plan, the Chief Executive Officer, the Executive Vice President, and the Senior Vice Presidents are measured 100% on the Corporate Goals Scorecard and Vice Presidents are measured 50% on the Corporate Goals Scorecard and 50% on the Business Area Goals Scorecard as set forth in Table 2 above.

The amount of the potential Award payable to any Officer based upon his or her Business Area’s level of achievement of its Performance Goals, expressed as a percentage of the Officer’s base salary determined as of January 1, 2010, is as follows:

TABLE 3:

Award Levels	Threshold	Target	Maximum
CEO	28.0%	70.0%	140.0%


Senior Officers	20.0%	50.0%	100.0%

Vice-Presidents	12.6%	31.5%	63.0%

The Selected Award Pool for a Business Area will be allocated among the Officers in that Business Area based upon the amount potentially payable to that Officer, as determined in accordance with Table 3, for the level of performance (Threshold, Target or Maximum) attained by Corporate and/or the relevant Business Area, as compared to the similar amounts payable to all Officers of that Business Area at the relevant performance level. The Selected Award Pool, the amount that will actually be paid to the Officers included in the appropriate Business Area, will equal the lesser of the Potential Award Pool (which as noted above is based solely on the EPS level) or the Performance Award Pool (which is based solely on performance as measured and calculated in accordance with the process above).

In no event will the amount payable to an Officer exceed the indicated percentage of the Officer’s base salary, as in effect on January 1, 2010, as determined in accordance with Table 3.

AWARD APPROVAL AND PAYOUT TIMING

In January 2011, the Committee will determine and certify the level of Awards, if any, payable for the Performance Period in the manner described above. The final Awards calculation and recommendation to the Committee by management is reviewed and certified by the VP, Human Resources, Director, Audit Services, Director, Management Systems group, and Corporate Controller respectively. The Board then will approve the CEO’s Award and the Committee will have final approval authority for all other Officer Awards. To the extent Awards are payable under the Plan, the Company will make such payment on or before March 15, 2011 in a single lump sum cash payment subject to applicable withholding as described below.

PROVISIONS FOR A CHANGE IN CONTROL

If a Change in Control occurs during the Performance Period and the Officer still is employed by the Company or an Affiliate (for purposes of this section, Optim and FCP are not included as Affiliates) at the end of the Performance Period, the Officer may be entitled to receive an Award for such Performance Period. If the Plan is modified after the occurrence of a Change in Control in a manner that has the effect of reducing the amounts otherwise payable under the Plan, the Officer shall receive, at a minimum, an Award equal to 50% of the Maximum Award available under this Plan for the Performance Period. Such Award will be payable in a single lump sum cash payment on or before March 15, 2011.

PRO-RATA AWARDS FOR PARTIAL SERVICE PERIODS

In certain circumstances (as set forth below) Officers may or may not be eligible for a Pro-rata Award under the Plan.

The following Officers may be eligible for a Pro-rata Award:

-	Officers who are newly hired during the Plan Year and are employed by the Company or an Affiliate (including FCP or Optim) on the day on which Awards are distributed for the Performance Period.

-	Employees or Officers who are promoted, transferred or demoted during the Performance Period and are employed by the Company or an Affiliate (including FCP or Optim) on the day on which Awards are distributed for the Performance Period.

-	Officers who are on leave of absence for any full months during the Performance Period and are employed by the Company or an Affiliate (including FCP or Optim) on the day on which Awards are distributed for the Performance Period.

Officers who terminate employment with the Company or an Affiliate during the Performance Period due to Impaction (as defined in the PNM Resources, Inc. Non-Union Severance Pay Plan), Retirement on or after the Officer’s Normal Retirement Date, Change in Control (as defined in the PNM Resources, Inc. Officer Retention Plan) or Disability (as defined in the PNM Resources Executive Savings Plan II).

-	Officers who die during the Performance Period, in which case the Award will be paid to the spouse of a married Officer, including same sex spouse, or the estate of an unmarried Officer.

The following Officers are not eligible for any Award, including a Pro-rata Award:

Officers who:

-Terminate employment with the Company or an Affiliate on or before the date on which Awards are distributed for the Performance Period for any reason other than death, Impaction, Retirement, Change in Control or Disability;

- Elect voluntary separation or Retirement in lieu of termination for performance or misconduct.

If an Officer is eligible for a Pro-rata Award, it will be calculated based on the number of full months that the Officer was actively employed at each eligibility level during the Performance Period compared to the number of full months included in the Performance Period. (Note: Any month in which an Officer is actively on the payroll for at least one day will count as a full month.) Any Pro-rata Awards to which an Officer becomes eligible pursuant to this paragraph will be paid to the Officer in a single lump sum cash payment subject to applicable withholding on or before March 15, 2011.

ETHICS

The purpose of the Plan is to fairly reward performance achievement. Any Officer who manipulates or attempts to manipulate the Plan for personal gain at the expense of customers, other employees, or the Company or its Affiliates, will be subject to disciplinary action, up to and including termination of employment, and will forfeit and be ineligible to receive any Award under the Plan.

NONTRANSFERABLE

No Award may be assigned or transferred by an Officer other than by will or the laws of descent and distribution of the State in which the Officer is employed.

WITHHOLDING

The Company or any Affiliate has the authority and the right to deduct or withhold, or to require an Officer to remit to the Company, an amount sufficient to satisfy federal, state, and local and foreign taxes (including the Officer’s FICA obligation) required by law to be withheld with respect to any taxable event arising as a result of this Plan. Any potential payment to an Officer under the terms of this Plan also is subject to withholdings and deductions by the Company or any Affiliate, and the Officer hereby authorizes the Company or any Affiliate to apply such withholdings and deductions to liquidate and reduce any outstanding debt or unpaid sums owed by the Officer to the Company or any Affiliate or to the successor of either of them.

NO RIGHTS OF OWNERSHIP

While the Plan is intended to provide Officers with the opportunity to share in the success of the Company and its Affiliates, the Plan is merely an incentive plan and does not give any Officer any of the rights of ownership of the Company or any Affiliate or provide any security interest in any assets of the Company or any Affiliate.

CONTINUATION OF EMPLOYMENT

This Plan shall not be construed to confer upon any Officer any right to continue in the employment of the Company or any Affiliate and shall not limit the right of the Company or any Affiliate, in its sole discretion, to terminate the employment of any Officer at any time, or in accordance with any written employment agreement the Company and Officer may have.

Approved by:

/s/ Alice A. Cobb

Alice A. Cobb, SVP and Chief Administrative Officer

March 31, 2010

Date

Exhibit 10.4

PERFORMANCE

RESTRICTED STOCK RIGHTS AWARD AGREEMENT

PNM RESOURCES, INC. SECOND AMENDED AND RESTATED

OMNIBUS PERFORMANCE EQUITY PLAN

PNM Resources, Inc., a New Mexico corporation, (“PNMR” or the “Company”) hereby awards to «First» «Last» , (the “Grantee”), a Participant in the PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan (the “Plan”), as it may be amended, a Performance Restricted Stock Rights Award (the “Award”) for the number of shares of common stock of Company (“Stock”) noted below. The grant is made effective as of the ____ day of March, 2010 (the “Grant Date”).

Capitalized terms used in this Performance Restricted Stock Rights Award Agreement (the “Agreement”) and not otherwise defined herein shall have the meanings given to such terms in the Plan.

1. Grant . Company hereby awards Grantee an opportunity to earn Restricted Stock Rights at the Threshold, Target or Maximum Award level listed in Section 4, based upon Company’s performance over the Performance Period (as defined in Section 3, in accordance with and subject to the terms and conditions set forth in this Agreement. In no event will the Award exceed the Maximum Award level indicated in Section 4. If Grantee is a Covered Employee, the Award is intended to be a Performance-Based Award granted pursuant to Section 12 of the Plan.

2. Award Subject to Plan . This Award is granted pursuant to the Plan, the terms of which are hereby incorporated by reference.

3. Performance Period . The Performance Period for this Award begins on January 1, 2010 and ends on December 31, 2010.

4. Performance Goals; Number of Restricted Stock Rights Earned . Grantee will earn Restricted Stock Rights based upon the level of Company’s Adjusted Cash Earnings during the Performance Period as set forth below:

If Company’s Adjusted Cash Earnings over the Performance Period are:	The number of Restricted Stock Rights awarded to Grantee will be:
At least $275 MM (but not $310 MM)	__________ (the Threshold Award), adjusted as described below.
At least $310 MM (but not $345 MM)	__________ (the Target Award), adjusted as described below.
$345 MM or more	__________ (the Maximum Award)

If Company’s Adjusted Cash Earnings for the Performance Period are less than $275,000,000, no Restricted Stock Rights will be due pursuant to the Agreement. If Company’s Adjusted Cash Earnings for the Performance Period exceed $275,000,000 but are less than

$310,000,000, the number of Restricted Stock Rights to which Grantee is entitled will be interpolated between the Threshold and Target Award levels. If Company’s Adjusted Cash Earnings for the Performance Period exceed $310,000,000 but are less than $345,000,000, the number of Restricted Stock Rights to which Grantee is entitled will be interpolated between the Target and Maximum Award levels.

5. Adjusted Cash Earnings . For purposes of solely measuring performance under the Agreement, “Adjusted Cash Earnings” is defined as the amount of the Company’s net cash flow from operating activities (as reflected on the Company’s cash flow statement) adjusted for certain items. Specific adjustments to the Company’s net cash flow from operating activities include the following: (1) adding amounts received by the Company as principal payments on the Palo Verde lessor notes, (2) adding amounts received by the Company as Palo Verde 3 toll revenue, (3) including amounts attributable to Optim Energy, LLC cash earnings, (4) excluding changes in the Company’s working capital, and (5) excluding the impacts of the Valencia Non-Controlling Interest. The Adjusted Cash Earnings levels are not necessarily identical to any earnings outlook or guidance that may be announced by the Company and are structured to ensure that Award payments are not artificially inflated or deflated.

6. Determination of Adjusted Cash Earnings and Restricted Stock Rights Award . The Committee will determine the Adjusted Cash Earnings for the Performance Period and Grantee’s corresponding Restricted Stock Rights Award, if any, on or before February 28, 2011. The Committee then will submit its determinations with respect to the Adjusted Cash Earnings and the number of Restricted Stock Rights to which Grantee is entitled to the Board of Directors for review and approval. The date on which the Board of Directors approves the number of Restricted Stock Rights is referred to below as the “Determination Date.” The Restricted Stock Rights to which Grantee is entitled pursuant to this Section shall vest and become payable at the times described in Sections 7 and 8.

7. Vesting .

(a) Except as set forth below, the Restricted Stock Rights to which Grantee is entitled shall vest in the following manner: (i) 33% of the Restricted Stock Rights will vest on the first anniversary of the Determination Date, (ii) an additional 34% of the Restricted Stock Rights will vest on the second anniversary of the Determination Date, and (iii) the final 33% of the Restricted Stock Rights will vest on the third anniversary of the Determination Date.

(b) Upon Grantee’s Separation from Service due to death, Disability, Retirement, Impaction or Change in Control prior to the end of the Performance Period, Grantee shall vest in a pro rata portion of the Restricted Stock Rights to which Grantee is entitled at the end of the Performance Period as described in Subsection 13.1(a)(iii)(3) of the Plan. The number of Restricted Stock Rights to which Grantee is entitled hereunder shall be determined at the conclusion of the Performance Period based upon actual performance during the Performance Period.

(c) Upon Grantee’s Separation from Service due to death, Disability, Retirement, Impaction or Change in Control after the conclusion of the Performance Period, nonvested Restricted Stock Rights shall become 100% vested in accordance with Subsection 13.1(a)(iii)(3) of the Plan.

(d) Upon Grantee’s involuntary or voluntary Separation from Service for any reason other than those set forth in Subparagraphs (b) and (c) above, the Restricted Stock Rights, if not previously vested, shall be canceled and forfeited immediately.

(e) Upon Grantee’s Separation from Service for Cause, all nonvested Restricted Stock Rights shall be canceled and forfeited immediately.

8. Form and Timing of Delivery of Stock .

(a) If any Restricted Stock Rights granted hereunder vest as described in Section 7(a), Grantee will receive the Stock payable with respect to such vested Restricted Stock Rights within ninety (90) days following the dates on which the Restricted Stock Rights vest.

(b) If any Restricted Stock Rights granted hereunder vest as described in Section 7(b), Grantee will receive the Stock within ninety (90) days following the end of the Performance Period.

(c) Except as otherwise provided in Section 8(d), if any Restricted Stock Rights granted hereunder vest as described in Section 7(c), Grantee will receive the Stock payable with respect to such Restricted Stock Rights within ninety (90) days following the date of Grantee’s Separation from Service.

(d) The Restricted Stock Rights granted hereunder are subject to the requirements of Section 409A of the Code. Accordingly, the restrictions described in Section 20.4 of the Plan apply to the Restricted Stock Rights. In addition, if Grantee is a Specified Employee at the time of Grantee’s Separation from Service, the six (6) month delay in payments to a Specified Employee upon a Separation from Service (described in Section 20.3 of the Plan) applies.

9. Adjustments . Neither the existence of the Plan nor the Award shall affect, in any way, the right or power of Company to make or authorize: any or all adjustments, recapitalizations, reorganizations, or other changes in Company’s capital structure or its business; or any merger or consolidation of Company; or any corporate act or proceeding, whether of a similar character or otherwise; all of which, and the resulting adjustments in, or impact on, the Award are more fully described in Section 5.3 of the Plan.

10. Withholding and Deductions . Company shall have the right to require that Grantee remit to Company an amount sufficient to satisfy any federal, state or local taxes of any kind as are required by law to be withheld with respect to the delivery of shares of Stock as payment for the Restricted Stock Rights granted hereunder. Company also shall have the right to take such other actions as may be necessary in the opinion of Company to satisfy all obligations for withholding and payment of such taxes. Company may, in its sole discretion, permit Grantee to elect to satisfy the minimum statutory tax withholding obligation which may arise in connection with the Restricted Stock Rights by requesting that Company withhold shares of Stock having a Fair Market Value on the date of withholding equal to the amount of the minimum statutory tax withholding. Any such election shall be subject to the provisions of applicable law and to any conditions the Committee may determine to be necessary in order to comply with all applicable withholding requirements and the applicable conditions of Rule 16b-3 or its successors under the Exchange Act.

11. Dividend Equivalents . Grantee will not be entitled to receive a dividend equivalent for any of the Restricted Stock Rights granted hereunder.

12. Compliance with Exchange Act . If Grantee is subject to Section 16 of the Exchange Act, Restricted Stock Rights granted pursuant to this Award are intended to comply with all applicable conditions of Rule 16b-3 or its successors under the Exchange Act.

13. Non-Assignability . The Award and Grantee’s rights under this Agreement shall not be transferable other than by will or by the laws of descent and distribution. The Restricted Stock Rights are otherwise non-assignable. (See Section 14 of the Plan). The terms hereof shall be binding on the executors, administrators, heirs and successors of Grantee.

14. Voting Rights . During the Restricted Period, Grantee will have no voting rights with respect to nonvested Restricted Stock Rights.

15. Grantee Representation . As a condition to the receipt of any shares of Stock hereunder, Company may require a representation from Grantee that the Stock is being acquired only for investment purposes and without any present intention to sell or distribute such shares.

16. Employment Agreement . Notwithstanding anything to the contrary contained in this Agreement, (a) neither the Plan nor this Agreement is intended to create an express or implied contract of employment for a specified term between Grantee and Company and (b) unless otherwise expressed or provided, in writing, by an authorized officer, the employment relationship between Grantee and Company shall be defined as “employment at will” wherein either party, without prior notice, may terminate the relationship with or without cause.

17. Regulatory Approvals and Listing . Company shall not be required to issue any certificate for shares of Stock upon the vesting of Restricted Stock Rights granted under this Agreement prior to satisfying any regulatory approval, registration, qualification or other requirements of the Securities and Exchange Commission, the Internal Revenue Service or any other governmental agency which the Committee, in its sole discretion, shall determine to be necessary or advisable. (See Section 20.1 of the Plan).

18. Administration . This Agreement shall at all times be subject to the terms and conditions of the Plan and the Plan shall in all respects be administered by the Committee in accordance with the terms of and as provided in the Plan. The Committee shall have the sole and complete discretion with respect to the interpretation of this Agreement and the Plan, and all matters reserved to it by the Plan. The decisions of the majority of the Committee with respect thereto and to this Agreement shall be final and binding upon Grantee and Company. In the event of any conflict between the terms and conditions of this Agreement and the Plan, the provisions of the Plan shall control.

19. Waiver and Modification . The provisions of this Agreement may not be waived or modified unless such waiver or modification is in writing signed by Company.

20. Validity and Construction . The validity and construction of this Award shall be governed by the laws of the State of New Mexico.

MANY OF THE PROVISIONS OF THIS AWARD AGREEMENT ARE SUMMARIES OF SIMILAR PERTINENT PROVISIONS OF THE PLAN. TO THE EXTENT THIS

AGREEMENT IS SILENT ON AN ISSUE OR THERE IS A CONFLICT BETWEEN THE PLAN AND THIS AGREEMENT, THE PLAN PROVISIONS SHALL CONTROL.

IN WITNESS WHEREOF, Company has caused this Performance Restricted Stock Rights Award Agreement to be executed on March __, 2010, by a duly authorized representative.

PNM RESOURCES, INC.

Alice A. Cobb

Senior Vice President and

Chief Administrative Officer

Exhibit 10.5

PERFORMANCE CASH AWARD AGREEMENT

PNM RESOURCES, INC. SECOND AMENDED AND RESTATED

OMNIBUS PERFORMANCE EQUITY PLAN

PNM Resources, Inc., a New Mexico corporation, (“PNMR” or the “Company”) hereby awards to «First» «Last» , (the “Participant”) a Participant in the PNM Resources, Inc. Second Amended and Restated Omnibus Performance Equity Plan (the “Plan”), as it may be amended, a Performance Cash Award (the “Award”) effective as of the ___ day of March, 2010.

Capitalized terms used in this Performance Cash Award Agreement (the “Agreement”) and not otherwise defined herein shall have the meanings given to such terms in the Plan.

1. Grant . Company hereby awards to Participant the opportunity to earn a cash payment in an amount equal to the Threshold, Target or Maximum Award level listed in Section 4, based upon Company’s performance over the Performance Period (defined in Section 3), in accordance with and subject to the terms and conditions set forth in this Agreement. In no event will the Award exceed the Maximum Award level indicated in Section 4. If Participant is a Covered Employee, the Award is intended to be a Performance-Based Award granted pursuant to Section 12 of the Plan.

2. Award Subject to Plan . This Award is granted pursuant to the Plan, the terms of which are hereby incorporated by reference.

3. Performance Period . The Performance Period for this Award begins on January 1, 2010 and ends on December 31, 2010.

4. Performance Goals; Amount of Award . The amount of the Award to which Participant is entitled pursuant to this Agreement, if any, is based upon the level of Company’s Adjusted Cash Earnings during the Performance Period as set forth below:

If Company’s Adjusted Cash Earnings over the Performance Period are:	The Annual Performance Cash Award awarded to Participant will be:
At least $275 MM (but not $310 MM)	$__________ (the Threshold Award), adjusted as described below.
At least $310 MM (but not $345 MM)	$__________ (the Target Award), adjusted as described below.
$345 MM or more	$__________ (the Maximum Award)

If Company’s Adjusted Cash Earnings for the Performance Period are less than $275,000,000, no payment will be due pursuant to this Agreement. If Company’s Adjusted Cash Earnings for the Performance Period exceed $275,000,000 but are less than $310,000,000, the amount of the payment to which Participant is entitled will be interpolated between the Threshold and Target Award levels. If Company’s Adjusted Cash Earnings for the Performance

Period exceed $310,000,000 but are less than $345,000,000, the amount of the payment to which Participant is entitled will be interpolated between the Target and Maximum Award levels.

6. Determination of Adjusted Cash Earnings and Awards Payable . The Committee will determine the Adjusted Cash Earnings for the Performance Period and the amount of the Award to which Participant is entitled, if any, on or before February 28, 2011. If Participant is Company’s CEO, the Committee then will submit its determinations with respect to the Adjusted Cash Earnings and the amount to which such Participant is entitled to the Board of Directors for review and approval. No amount will be payable to such Participant in the absence of approval by the Board of Directors.

7. Form and Timing of Payment . Participant will receive the payment, if any, on or before March 15, 2011.

8. Termination of Employment Due to Death, Disability, Retirement, Impaction or Change in Control Prior to Payment of Award . Upon Participant’s Termination of Employment due to death, Disability, Retirement, Impaction or Change in Control prior to the end of the Performance Period, Participant shall vest in a pro rata portion of the Award to which Participant is entitled at the end of the Performance Period based on the level of achievement of the Performance Goals described in Section 4. The payment to which Participant is entitled for the pro rata portion of the vested Award shall be based on the number of full months included in the Performance Period as of the date of Participant’s Termination of Employment compared to the number of full months included in the Performance Period. The amount of the Award to which Participant is entitled hereunder shall be determined at the conclusion of the Performance Period based upon actual performance during the Performance Period. The Award, if any, shall be paid at the time and in the form described in Section 7.

9. Withholding and Deductions . Company is authorized to withhold from any payments called for by this Agreement all withholding and other taxes due to the federal and any state governments and to take such other action as Company may deem necessary or advisable to enable Company and Participants to satisfy obligations for the payment of withholding taxes and other tax liabilities relating to any payment.

10. Non-Assignability . The Award and Participant’s rights under this Agreement shall not be transferable other than by will or by the laws of descent and distribution. The

Performance Cash Award is otherwise non-assignable. (See Section 14 of the Plan). The terms of this Agreement and the Plan shall be binding on the executors, administrators, heirs and successors of Participant.

11. Employment Agreement . Notwithstanding anything to the contrary contained in this Agreement, (a) neither the Plan nor this Agreement is intended to create an express or implied contract of employment for a specified term between Participant and Company and (b) unless otherwise expressed or provided, in writing, by an authorized officer, the employment relationship between Participant and Company shall be defined as “employment at will” wherein either party, without prior notice, may terminate the relationship with or without cause.

12. Administration . This Agreement shall at all times be subject to the terms and conditions of the Plan and the Plan shall in all respects be administered by the Committee in accordance with the terms of and as provided in the Plan. The Committee shall have the sole and complete discretion with respect to the interpretation of this Agreement and the Plan, and all matters reserved to it by the Plan. The decisions of the majority of the Committee with respect thereto and to this Agreement shall be final and binding upon Participant and Company. In the event of any conflict between the terms and conditions of this Agreement and the Plan, the provisions of the Plan shall control.

13. Waiver and Modification . The provisions of this Agreement may not be waived or modified unless such waiver or modification is in writing signed by Company.

14. Validity and Construction . The validity and construction of this Agreement shall be governed by the laws of the State of New Mexico.

MANY OF THE PROVISIONS OF THIS AWARD AGREEMENT ARE SUMMARIES OF SIMILAR PERTINENT PROVISIONS OF THE PLAN. TO THE EXTENT THIS AGREEMENT IS SILENT ON AN ISSUE OR THERE IS A CONFLICT BETWEEN THE PLAN AND THIS AGREEMENT, THE PLAN PROVISIONS SHALL CONTROL.

IN WITNESS WHEREOF, Company has caused this Performance Cash Award Agreement to be executed on March ___, 2010 by its duly authorized representative.

PNM RESOURCES, INC.

Alice A. Cobb

Senior Vice President and

Chief Administrative Officer

Exhibit 10.6

MUNICIPAL EFFLUENT PURCHASE AND SALE AGREEMENT

This MUNICIPAL EFFLUENT PURCHASE AND SALE AGREEMENT (this “Agreement”) is entered by and between City of Phoenix (“Phoenix”), City of Mesa, City of Tempe, City of Scottsdale, and City of Glendale, Arizona municipal corporations (collectively the “Subregional Operating Group” and hereinafter referred to as the “SROG Cities” and individually as a “SROG City”); and Arizona Public Service Company, an Arizona corporation (“APS”), and Salt River Project Agricultural Improvement and Power District, an Arizona municipal corporation and agricultural improvement district (“SRP”), acting on behalf of themselves and El Paso Electric Company, a Texas corporation, Southern California Edison Company, a California corporation, Public Service Company of New Mexico, a New Mexico corporation, Southern California Public Power Authority, a California joint powers authority, and the Los Angeles Department of Water & Power, a municipal utility (hereinafter collectively referred to as the “Palo Verde Participants” and individually as a “Palo Verde Participant”). The SROG Cities and APS and SRP are sometimes individually referred to in this Agreement as a “Party” and collectively as the “Parties.”

RECITALS

WHEREAS, on April 23, 1973, the SROG Cities, along with the Town of Youngtown, and APS and SRP entered into that certain “Option and Purchase of Effluent Agreement” referred to as “Agreement No. 13904” under which, among other things, the municipalities agreed to sell and deliver treated wastewater discharged from the 91st Avenue wastewater treatment plant (“Effluent”), a municipal wastewater treatment plant jointly owned by the SROG Cities (the “91st Avenue WWTP”) and operated and maintained by Phoenix in its own behalf and as administrative agent for the other SROG Cities, for cooling use at the Palo Verde Nuclear Generating Station (“PVNGS”) operated and maintained by APS in its own behalf and as administrative agent for the other Palo Verde Participants;

WHEREAS, on April 17, 1989, in Arizona Public Service Co. v. Long , 160 Ariz. 429 (1989), the Supreme Court of Arizona held, among other things, that municipal sewage effluent is neither surface water nor groundwater; it is water that loses its original character as surface water or groundwater, does not reestablish its legal character until it is returned to the ground as either surface water or groundwater, and prior to such return of effluent to the ground as either surface water or groundwater, the municipalities creating it are free to contract for the disposition of said effluent;

C.	WHEREAS, the Effluent purchased and sold in accordance with the terms and conditions of this Agreement is intended by the Parties to meet the legal standards set forth in Arizona Public Service Co. v. Long regarding the SROG Cities’ disposition of effluent;

WHEREAS, pursuant to the terms of Agreement No. 13904, the SROG Cities are committed to make available to the Palo Verde Participants up to 105,000 acre-feet of Effluent per year through June 1, 2025, 70,000 acre-feet of Effluent per year through April 24, 2026, and 35,000 acre-feet of Effluent per year through November 25, 2027, after which time Agreement No. 13904 would terminate;

WHEREAS, on December 11, 2008, APS, acting in its capacity as operating agent of PVNGS, submitted to the United States Nuclear Regulatory Commission three operating license renewal applications, which, if granted, will allow each of the three units at PVNGS to operate for an additional 20 years beyond the current license termination dates, thereby potentially extending the operating life of PVNGS through 2047;

F.	WHEREAS, as a result of these PVNGS operating license extensions, the Palo Verde Participants desire to secure the right to continue purchasing and receiving Effluent from the SROG Cities through 2050;

WHEREAS, the Palo Verde Participants have determined that less than the entire 105,000 acre-foot quantity of Effluent the SROG Cities are committed to provide each year under Agreement No. 13904 is required to operate PVNGS at full capacity and, therefore, desire to reduce this quantity by 25,000 acre-feet per year;

H.	WHEREAS, the SROG Cities desire to continue selling Effluent for beneficial use at PVNGS and any other electric generating facilities located within 10 miles of PVNGS pursuant to the terms and conditions contained in this Agreement;

I.	WHEREAS, the extended sale and purchase of Effluent through 2050 will ensure the continued beneficial use of a renewable water source for power generation purposes while reducing the demand for non-renewable water supplies;

J.	WHEREAS, this Agreement is intended to replace Agreement No. 13904, which will be of no further force and effect upon the Effective Date (defined in Section 2, below) of this Agreement; and

WHEREAS, APS and SRP are entering into this Agreement on their own behalf and on behalf of the other Palo Verde Participants pursuant to authorizations conferred on APS and SRP under that certain Arizona Nuclear Power Project Participation Agreement effective September 4, 1973, as such agreement is amended from time to time (the “ANPP Participation Agreement”).

AGREEMENT

NOW, THEREFORE, in consideration of the mutual promises, terms, and conditions contained in this Agreement, and other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged by the Parties, the Parties agree as follows:

1.	Ownership Changes .

1.1. As to the Palo Verde Participants . Any person, partnership, corporation, or governmental body or agency (each, a “Person”) engaged in the generation, transmission, or distribution of energy that, after the Effective Date, becomes a Participant in PVNGS pursuant to Section 15 of the ANPP Participation Agreement shall be a Palo Verde Participant under this Agreement.

1.2. As to the SROG Cities . Any municipal corporation that, after the Effective Date, becomes the holder of an ownership interest in the 91 st Avenue WWTP shall be a SROG City under this Agreement.

Term and Termination Date . This Agreement shall become effective on the date on which this Agreement has been approved by the governing bodies of all of the Parties and is signed by all of the Parties (the “Effective Date”), and shall terminate on December 31, 2050, unless extended by mutual agreement of the Parties pursuant to Section 14, below.

3.	Effluent Deliveries; Quantity; Relinquishment .

3.1. Delivery Points . Throughout the term of this Agreement and in accordance with Section 3.2, below, Phoenix shall deliver up to 80,000 acre-feet of Effluent annually (the “Committed Quantity”) to the delivery points (the “Delivery Points”) interconnecting the 91 st Avenue WWTP with the PVNGS water reclamation supply system pipeline (the “WRSS Pipeline”) for transport to the PVNGS Water Reclamation Facility (the “PVNGS WRF”), which Delivery Points are depicted on Exhibit “A” attached to this Agreement. APS and Phoenix may from time to time, by mutual written agreement, designate additional points of delivery for the purpose of delivering Effluent to the WRSS Pipeline. Upon such designation, the new point of delivery shall become a Delivery Point under this Agreement.

3.2. Monthly Delivery Quantities .

3.2.1. Subject to Section 3.3, below, throughout the term of this Agreement, in each of the months from January through April and October through December, Phoenix shall make available for delivery to PVNGS up to 7,000 acre-feet of Effluent.

3.2.2. Subject to Section 3.3, below, throughout the term of this Agreement, in each of the months from May through September, Phoenix shall make available for delivery to PVNGS up to 8,000 acre-feet of Effluent.

3.3. Annual Delivery Quantities . Subject to Sections 3.5 and 7.2, below, Phoenix shall not be required to deliver more than the Committed Quantity of Effluent each calendar year under this Agreement.

3.4. Relinquishment of Portion of Committed Quantity .

3.4.1. The Palo Verde Participants may, upon six months’ prior written notice to Phoenix, which notice shall be given in accordance with the requirements of Section 28.3, below (the “Relinquishment Notice”), permanently relinquish a portion of the Committed Quantity. The Relinquishment Notice shall identify the quantity of Effluent the Palo Verde Participants desire to relinquish (the “Relinquished Quantity”) and the date on which the relinquishment shall become effective (the “Relinquishment Date”).

Unless otherwise agreed to in writing by the SROG Cities, as of the date of the Relinquishment Notice, neither the Relinquished Quantity nor Relinquishment Date may be subsequently modified by the Palo Verde Participants, nor may the Palo Verde Participants rescind the relinquishment described in the Relinquishment Notice. Upon the Relinquishment Date, the Relinquished Quantity shall be deducted from the Committed Quantity in effect as of the date of the Relinquishment Notice, and the difference shall become the new Committed Quantity under this Agreement unless and until later modified pursuant to this Section 3.4.1.

3.4.2. Unless otherwise agreed to by the Parties, modifications to the Committed Quantity pursuant to this Section 3.4 shall not affect the monthly delivery requirements set forth in Section 3.2, above.

3.4.3. As of the Relinquishment Date, the Relinquished Quantity of Effluent shall be available for the SROG Cities’ use, sale, or other disposition.

3.5. Substantial Change in Conditions . Section 3.4, above, notwithstanding, and subject to availability as reasonably in good faith determined and authorized by the SROG Cities, the Palo Verde Participants shall have the right to the delivery of additional quantities of Effluent for use consistent with the terms of this Agreement if certain conditions substantially change at PVNGS resulting in the need for additional Effluent. The additional quantities of Effluent resulting from substantially changed conditions pursuant to this Section 3.5 shall not be greater than 8,000 acre-feet per year during the term of this Agreement. The Per Acre-Foot Price (defined in Section 4.2, below) of any additional Effluent purchased by the Palo Verde Participants pursuant to this Section 3.5 shall be:

3.5.1. For calendar years 2010 through 2025, the Per Acre-Foot Price determined in accordance with Section 4.2.1, below;

3.5.2. For calendar years 2026 through 2050, the fourth tier Per Acre-Foot Price determined in accordance with Section 4.2.2, below.

Price . In consideration of the sale and delivery of Effluent from the SROG Cities throughout the term of this Agreement and the other services provided by the SROG Cities pursuant to this Agreement, the Palo Verde Participants shall make payments to Phoenix, on behalf of the SROG Cities, in the manner and as determined pursuant to this Section 4.

4.1. Water Supply Payments . The Palo Verde Participants shall pay Phoenix, on behalf of the SROG Cities, four lump-sum payments of 7.5 million dollars each (“Water Supply Payments”), which Water Supply Payments shall total 30 million dollars. The Palo Verde Participants shall pay the Water Supply Payments in accordance with the following schedule:

4.1.1. Within 30 days after the Effective Date, 7.5 million dollars;

4.1.2. 7.5 million dollars by January 31 of each of the years 2011 through 2013;

4.1.3. Upon the Palo Verde Participants’ full payment of 30 million dollars to the SROG Cities pursuant to this Section 4.1, no further Water Supply Payments shall be payable to the SROG Cities throughout the term of this Agreement.

4.2. Per Acre-Foot Payments . In addition to the Water Supply Payments described in Section 4.1, above, subject to Section 7.2, below, the Palo Verde Participants shall pay Phoenix, on behalf of the SROG Cities, for each acre-foot of Effluent actually delivered to the Delivery Points pursuant to this Agreement (“Delivered Effluent Quantity”), as measured by the Metering Devices (defined in Section 6, below). Beginning on the Effective Date, throughout the term of this Agreement, the Palo Verde Participants shall pay Phoenix, on behalf of the SROG Cities, for the previous month’s Delivered Effluent Quantity by multiplying the previous month’s Delivered Effluent Quantity by the applicable per acre-foot price (the product being the “Monthly Payment Amount”), as determined in accordance with Sections 4.2.1 and 4.2.2, below (the “Per Acre-Foot Price”).

4.2.1. Per Acre-Foot Price: 2010 through 2025 . For calendar years 2010 through 2025, the Palo Verde Participants shall pay Phoenix, on behalf of the SROG Cities, the Per Acre-Foot Prices contained in the following schedule:

Contract Year	Per Acre-Foot Price
2010	$58.57
2011	$64.71
2012	$71.51
2013	$79.02
2014	$87.31
2015	$96.48
2016	$106.61
2017	$117.81
2018	$130.18
2019	$143.85
2020	$158.95
2021	$175.64
2022	$194.08
2023	$214.46
2024	$236.98
2025	$261.86

4.2.2. Per Acre-Foot Price: 2026 through 2050 .

4.2.2.1. In calendar years 2026 through 2050, the Palo Verde Participants shall pay Phoenix, on behalf of the SROG Cities, a Per Acre-Foot Price based on the following escalating tiered rate structure, which is composed of four price tiers based on the monthly Delivered Effluent Quantity:

Tier	Delivered Effluent Quantity
1	0 – 2,000 acre-feet
2	2,001 – 4,000 acre-feet
3	4,001 – 6,000 acre-feet
4	6,001 – 8,000 acre-feet

4.2.2.2. For each of the years 2026 through 2028, the Per Acre-Foot Prices applicable to Tiers 1 through 4 shall remain fixed at $198.00, $293.00, $349.00, and $474.00, respectively.

4.2.2.3. Starting in 2029 and every year thereafter through 2050, subject to an annual cap of three percent, the preceding year’s Per Acre-Foot Price applicable to each tier shall be adjusted based on the simple average of the following three price indices as determined for that preceding calendar year: (i) Consumer Price Index – All Urban Consumers, U. S. City Average, Water and Sewerage Maintenance (not seasonally adjusted) [CUUR0000SEHG01)]; (ii) Consumer Price Index – All Urban Consumers, U.S. City Average, West Urban (not seasonally adjusted) [CUUR0400SA0, CUUS0400SA0]; and (iii) Consumer Price Index – All Urban Consumers, U.S. City Average, Electricity (not seasonally adjusted) [CUUR0000SEHF01, CUUS0000SEHF01] (the “Indices Basket”). Should any of the price indices in the Indices Basket be discontinued, the Parties shall substitute another such index generally recognized to be authoritative with respect to the subject matter of the discontinued index and this Agreement.

4.2.3. Monthly Billings and Payments . By the fifth business day of each month, APS shall provide to Phoenix the flow information necessary to calculate the Monthly Payment Amount, which flow information shall be sent by facsimile or electronic mail and regular United States Mail. Using the flow information provided by APS pursuant to this Section 4.2.3, Phoenix shall invoice APS for the Monthly Payment Amount by the fifteenth day of the same month in which the flow information was received from APS; and APS shall pay Phoenix, on behalf of the SROG Cities, the Monthly Payment Amount by the last day of that same month. Provided Phoenix

has properly invoiced APS pursuant to this Section 4.2.3, if APS fails to pay the Monthly Payment Amount by the due date thereof, Phoenix shall notify APS of such delinquent payment (the “Monthly Payment Delinquency Notice”), and APS shall pay the entire amount owed to Phoenix within 15 days after receipt of the Monthly Payment Delinquency Notice. If APS fails to pay the entire amount owed to Phoenix within 15 days of receipt of the Monthly Payment Delinquency Notice, beginning on the date on which the Monthly Payment Amount was originally due, interest shall accrue on the delinquent amount at a rate of one percent per month until paid.

5.	Non-Usage Fees .

5.1. Calculation of Non-Usage Fee . Subject to Section 5.3, below, throughout the term of this Agreement, if APS does not take delivery of the entire Committed Quantity in a calendar year, in addition to any other payments owed to the SROG Cities pursuant to Section 4, above, the Palo Verde Participants shall pay a fee to Phoenix, on behalf of the SROG Cities, based on the difference between the Committed Quantity and Delivered Effluent Quantity in such year (the “Non-Usage Fee”). The Non-Usage Fee shall be calculated in accordance with the following schedule ( see attached Appendix for illustrative examples of Non-Usage Fee calculations):

5.1.1. 2010 through 2025 . For calendar years 2010 through 2025, the Non-Usage Fee shall be calculated by subtracting the Delivered Effluent Quantity in the calendar year (DQ) from the Committed Quantity in that same year (CQ) and multiplying the difference by 20 percent of the Per Acre-Foot Price (PP) applicable in that year (as determined in accordance with Section 4.2.1, above); or [(CQ – DQ) x PP x .20].

5.1.2. 2026 through 2050: Non-Extended Outage Periods . Subject to Section 5.1.3, below, for calendar years 2026 through 2050, the Non-Usage Fee shall be calculated by subtracting the Delivered Effluent Quantity in the calendar year (DQ) from the Committed Quantity in that same year (CQ) and multiplying the difference by 30 percent of the simple average per acre-foot price applicable in that year, which average per acre-foot price shall be determined by adding the Per Acre-Foot Price applicable to each of the four tiers in the relevant year, (as determined in accordance with Section 4.2.2, above) and dividing the total by four (“Average Per Acre-Foot Price” or (AP)); or [(CQ – DQ) x AP x .30].

For example, because, in 2026, the Per Acre-Foot Prices for tiers 1 through 4 are set at $198, $293, $349, and $474, respectively, the Average Per Acre-Foot Price for these four tiers is $328.50. If 75,000 acre-feet (AF) of water was delivered to PVNGS in 2026 and the Committed Quantity was 80,000 acre-feet in that year, assuming there were no Extended Outage Periods (defined in Section 5.1.3.1, below), the Non-

Usage Fee payable to the SROG Cities by January 31, 2027 would be $492,750 ((80,000 AF – 75,000 AF) x $328.50 x .30).

5.1.3. 2026 through 2050: Extended Outage Periods . For calendar years 2026 through 2050, in lieu of the formula set forth in Section 5.1.2, above, if any PVNGS electric generating unit is shut down (“Outage Unit”) for an Extended Outage Period (defined in Section 5.1.3.1, below), the Non-Usage Fee applicable to each Outage Unit during the Extended Outage Period only shall be determined by using the “Representative Usage” (defined in Section 5.1.3.2, below) of such unit. The Non-Usage Fee payable for each Outage Unit during the Extended Outage Period shall be calculated by multiplying the Representative Usage (RU) by 20 percent of the Average Per Acre-Foot Price (AP) applicable in that year; or [RU x AP x .20].

5.1.3.1. “Extended Outage Period” shall mean a period of 90 or more consecutive days over which a PVNGS electric generating unit is shut down. The Extended Outage Period shall commence on the day the electric generating unit is shut down and shall terminate on the day the electric generating unit has resumed full power generation. For purposes of this Section 5, “full power” means operation of a PVNGS electric generating unit at or near maximum generation with consideration for ambient temperature, regulatory requirements, and equipment conditions.

5.1.3.2. “Representative Usage” is an estimate of the quantity of Effluent the Outage Unit would have used had it not experienced an Extended Outage Period, and is necessary to calculate the Non-Usage Fee for that Extended Outage Period. The Representative Usage shall equal the average Effluent usage over the entirety of the Extended Outage Period of the two remaining PVNGS electric generating units that operated at full power during such period. If only one PVNGS electric generating unit operated at full power during the entirety of the Extended Outage Period, the Representative Usage shall equal the Effluent usage of that unit over such period. If none of the PVNGS electric generating units operated at full power over the entirety of the Extended Outage Period, the Representative Usage shall be determined by considering the Effluent usage during the most recent year in which at least one PVNGS electric generating unit operated at full power over the same period of time as the Extended Outage Period. If during the entirety of such prior time period more than one unit operated at full power, the average Effluent usage of those units shall be used to calculate the Representative Usage.

For example, on March 17, 2026, PVNGS Unit 3 shuts down and does not resume full power generation until June 20, 2026. In

addition, during this time frame, Units 2 and 3 experience short-term outages, each lasting a few weeks. Because none of the three PVNGS electric generating units operated continuously over the entire March 17 through June 20, 2026 time frame, it is necessary to consider the average Effluent usage for the electric generating units operating at full power during the entirety of the March 17, 2025 through June 20, 2025 period (or the Effluent usage of one unit if it was the only unit that operated at full power over the entirety of that period) in order to determine the Representative Usage. If such data is not available over the March 17, 2025 through June 20, 2025 period because all three units experienced an outage sometime during that period, the March 17, 2024 through June 20, 2024 period will be considered. This process will continue until the Representative Usage for at least one PVNGS unit operating at full power can be determined.

5.1.3.3. Flow Measurements during Extended Outage Period . For purposes of determining the Representative Usage pursuant to Section 5.1.3.2, above, APS shall take a totalizer reading off the Metering Devices of Effluent transferred from the PVNGS reservoirs to the circulating water canals of the PVNGS electric generating units when the Outage Unit ceases operating at full power, and a second totalizer reading when the Outage Unit resumes operating at full power. The totalizer readings taken during the year used to determine the Representative Usage shall be used as the basis for calculating the Non-Usage Fee pursuant to this Section 5.1.3.

5.1.3.4. Calculation of Non-Usage Fees in Extended Outage Period Years . In any year in which Non-Usage Fees are paid pursuant to this Section 5.1.3, the total quantity of Effluent on which such payment or payments are based shall be subtracted from the Committed Quantity in that year when determining the Non-Usage Fee payable pursuant to Section 5.1.2, above. Thus, the Non-Usage Fee payable pursuant to Section 5.2, below, shall be calculated by subtracting the Delivered Effluent Quantity in the relevant calendar year (DQ) and the total Representative Usage (RU) in that same year from the Committed Quantity in such year (CQ) and multiplying the difference by 30 percent of the Average Per Acre-Foot Price (AP) applicable in that year; or [(CQ – DQ – RU) x AP x .30].

For example, on March 17, 2026, PVNGS Unit 3 shuts down and does not resume full power generation until June 20, 2026; the Representative Usage over the Extended Outage Period for the Outage Unit was 6,500 acre-feet (AF). Assuming a Committed Quantity of 80,000 acre-feet, a Delivered Effluent Quantity of

68,500 acre-feet, and an Average Per Acre-Foot Price in 2026 of $328.50, the total Non-Usage Fees payable to Phoenix by January 31, 2027 would be calculated as follows:

Extended Outage Period : 6,500 AF x $328.50 x .20 = $427,050 (Section 5.1.3)

Non-Extended Outage Period : (80,000 AF – 68,500 AF – 6,500 AF) x $328.50 x .30 = $492,750 (Section 5.1.3.4)

Total Non-Usage Fees (2026) : $427,050 + $492,750 = $919,800

5.1.3.5. Extended Outage Periods over Multiple Calendar Years: Existence Known as of December 31 . In the event an Extended Outage Period extends from the calendar year for which a Non-Usage Fee is payable into the following calendar year, and the existence of that Extended Outage Period is known as of December 31 of the year for which the Non-Usage Fee is payable, the Representative Usage shall be treated as follows: The Representative Usage based on that portion of the Extended Outage Period extending from the date on which the Extended Outage Period commenced through December 31 of that same year shall be used to calculate the Non-Usage Fee payable for that year. Additionally, the Representative Usage based on that portion of any Extended Outage Period extending from January 1 of any subsequent year through the earlier of the date on which the Extended Outage Period terminates, or December 31 of that year, shall be included in the calculation of the Non-Usage Fee payable for such year.

5.1.3.6. Extended Outage Periods over Multiple Calendar Years: Existence Unknown as of December 31 . In the event an Extended Outage Period extends from the calendar year for which a Non-Usage Fee is payable into the following calendar year, but the existence of that Extended Outage Period was not known as of December 31 of the year for which the Non-Usage Fee is payable and did not become known until the following year, 10 percent of that portion of the Non-Usage Fee paid for such year, which is attributable to that part of the Extended Outage Period that occurred between the date on which the Extended Outage Period commenced through December 31 of that same year (which portion of the Non-Usage Fee would have been paid pursuant to Section 5.1.2, above) shall be credited against the Non-Usage Fee payable for the following year and, to the extent the credit is not depleted, the remainder will be credited against the Non-Usage Fee payable in any subsequent years until depleted. That portion of the Non-Usage Fee for any

part of the Extended Outage Period extending from January 1 of the year immediately following the year in which the Extended Outage Period commenced shall be determined in accordance with Section 5.1.3.5, above.

5.1.3.7. Extended Outage Periods over Multiple Calendar Years: Applicable Per Acre-Foot Price . In any year in which an Extended Outage Period extends over multiple calendar years pursuant to Sections 5.1.3.5 and 5.1.3.6, above, the Average Per Acre-Foot Price used to calculate the Non-Usage Fee in accordance with this Section 5.1.3 shall be determined with reference to the Per Acre-Foot Price applicable in the calendar year in which that portion of the Extended Outage Period actually occurred.

5.2. Payment of Non-Usage Fees . By the tenth day of each January, APS shall provide to Phoenix the Representative Usage, along with the totalizer readings and calculations used to determine the Representative Usage, which totalizer readings and calculations shall be sent by facsimile or electronic mail and regular United States Mail. By the twentieth day of each January, Phoenix shall invoice APS for the Non-Usage Fee calculated pursuant to Section 5.1, above; and APS shall pay Phoenix, on behalf of the SROG Cities, the entire Non-Usage Fee by January 31 of that same year. Provided Phoenix has properly invoiced APS pursuant to this Section 5.2, if APS fails to pay the Non-Usage Fee by the due date thereof, Phoenix shall notify APS of such delinquent payment (the “Non-Usage Fee Delinquency Notice”), and APS shall pay the entire amount owed to Phoenix within 15 days after receipt of the Non-Usage Fee Delinquency Notice. If APS fails to pay the entire amount owed to Phoenix within 15 days of receipt of the Non-Usage Fee Delinquency Notice, beginning on the date on which the Non-Usage Fee was originally due, interest shall accrue on the delinquent amount at a rate of one percent per month until paid.

5.3. No Non-Usage Fee Payable upon Occurrence of Certain Events . To the extent an event that may significantly impair Phoenix’s ability to comply with the SROG Cities’ obligations under this Agreement (as described in Section 9.2, below) results in a decrease in the quantity of Effluent the Palo Verde Participants would have otherwise taken under this Agreement, no Non-Usage Fee shall apply to such quantity.

Metering Devices . Metering devices installed by APS (“Metering Devices”) shall be used to measure the quantity of Effluent delivered to the Delivery Points and to measure Effluent flows for purposes of calculating the Representative Usage. Title to the Metering Devices shall be vested in the Palo Verde Participants. The Metering Devices shall be the basis for determining the Delivered Effluent Quantity. The Metering Devices shall be of a design and type acceptable to Phoenix and APS. The Palo Verde Participants shall bear the cost of the Metering Devices and the cost to install, operate, maintain, repair, replace, and calibrate the Metering Devices. APS shall calibrate the

Metering Devices no less frequently than once every six months. The SROG Cities may request in writing additional calibrations of the Metering Devices by an independent third party; provided that the cost incurred by the Palo Verde Participants for each additional calibration shall be reimbursed by the SROG Cities unless any such additional calibration reveals that the inaccuracy of the Metering Devices is greater than plus or minus two percent, in which case the cost of such additional calibration shall be borne by the Palo Verde Participants.

7.	Effluent Quality .

7.1. Minimum Quality Standards . At all times throughout the term of this Agreement, the quality of Effluent delivered by Phoenix to the Delivery Points shall (i) be of equal or better quality as the Effluent discharged from the 91 st Avenue WWTP to the Tres Rios constructed wetlands project; and (ii) meet or exceed the 91 st Avenue WWTP’s applicable federal and state discharge permit limits, including any amendments or replacements thereof as may be made from time to time.

7.2. Additional Effluent for Failure to Meet Minimum Quality Standards . Throughout the term of this Agreement, if, in any calendar year, the quality of Effluent delivered by Phoenix does not meet the minimum quality standards set forth in Section 7.1, above, and, as a result of such failure, cooling water usage at PVNGS is increased above 75,000 acre-feet per year based on an analysis of past blowdown rates to the PVNGS evaporation ponds, upon request by APS, Phoenix shall provide any additional Effluent required at no charge to the Palo Verde Participants up to, but not exceeding, 10 percent of the Committed Quantity for that calendar year. The additional quantity of Effluent required by this Section 7.2 shall be independent of and in addition to any additional quantities of Effluent delivered to PVNGS pursuant to Section 3.5, above. Any additional Effluent provided pursuant to this Section 7.2 shall not be a part of the Committed Quantity.

7.3. Discharge of TDS Concentrate Prohibited . The SROG Cities shall not discharge any total-dissolved-solids concentrate at any point downstream of the 91 st Avenue WWTP headworks, including, without limitation, the Delivery Points. By way of example, but not limitation, the SROG Cities shall not discharge reverse osmosis concentrate streams at such points.

8.	Operation and Maintenance .

8.1. SROG Cities . Phoenix shall operate, maintain, repair, and replace, at the SROG Cities’ expense, the 91st Avenue WWTP as is necessary to enable the SROG Cities to carry out their obligations pursuant to Sections 3 and 7, above.

8.2. Palo Verde Participants . APS shall operate, maintain, repair, and replace, at the Palo Verde Participants’ expense, all facilities, structures, and equipment owned, leased, or operated by the Palo Verde Participants, wherever located, used or useful for the receipt, treatment, storage, transportation, and use of Effluent,

including, without limitation, all such facilities, structures, and equipment that may be located on property owned by the SROG Cities or any of them (“Participants’ Facilities”). Phoenix and APS may agree by separate agreement that Phoenix shall operate and maintain certain of Participants’ Facilities or engage in other activities for the Palo Verde Participants and shall be compensated therefor.

9.	Practices and Procedures .

9.1. APS .

9.1.1. Throughout the term of this Agreement, by June 30 of each year, APS shall provide Phoenix with a schedule setting forth the quantities of Effluent anticipated to be needed during each month of the following year.

9.1.2. Except in the event of an unplanned, unscheduled outage, APS shall give Phoenix 30 days’ written notice in advance of any outage event. This notice shall include the date of the shutdown and the estimated duration of the outage.

9.1.3. If an unplanned, unscheduled outage or any other event results in a “Substantial Decrease” (defined below) in the quantity of Effluent required by PVNGS, APS shall notify Phoenix of the decreased Effluent quantity requirements as soon as reasonably practicable. “Substantial Decrease” shall mean a decrease in flow requirements of greater than 2,000 gallons per minute over a six-hour period. By way of example, but not limitation, “an unplanned, unscheduled outage or any other event” resulting in a Substantial Decrease in the quantity of Effluent required by PVNGS might include a short-notice outage of an electric generating unit, a power failure at the Hassayampa pump station, or equipment failure at the PVNGS WRF. APS shall use its best efforts to minimize the duration of any unplanned, unscheduled outage or any other events that result in a Substantial Decrease in the quantity of Effluent required by PVNGS under this Agreement. The notice required by this Section 9.1.3 shall include information detailing the reason for the decreased flow requirement and when the event giving rise to the decreased flow requirement first occurred, the expected duration of the decreased flow requirement, and on what date a return to full operating capacity is expected.

9.2. Phoenix . As soon as reasonably practicable, Phoenix shall notify APS of any event that may significantly impair Phoenix’s ability to comply with the SROG Cities’ obligations under this Agreement, including, without limitation, the requirements of Section 3, above, regarding quantity and the requirements of Section 7, above, regarding quality. By way of example, but not limitation, an “event that may significantly impair Phoenix’s ability to comply with the SROG Cities’ obligations under this Agreement” might include the loss or impairment of portions of the 91 st Avenue WWTP’s wastewater collection system, including,

without limitation, interceptors, or operational anomalies at the 91 st Avenue WWTP that have the potential to significantly change the quantity or quality of the Effluent delivered to the Palo Verde Participants. Phoenix shall use its best efforts to minimize the duration of any events that may significantly impair Phoenix’s ability to comply with the SROG Cities’ obligations under this Agreement. The notice required by this Section 9.2 shall include information detailing the cause of the event that significantly impairs Phoenix’s ability to comply with the SROG Cities’ obligations under this Agreement and when the event first occurred, the expected duration of such event, and by what date a return to normal operations is expected.

9.3. Contact by Third Parties . The SROG Cities shall not command, authorize, direct, or instruct their agents, consultants, or contractors to contact PVNGS, including the PVNGS WRF, without the prior consent of APS.

10.

New Treatment Plants . The SROG Cities shall install, operate, and maintain any new wastewater treatment plants and water reclamation plants constructed at any location other than the site of the 91st Avenue WWTP in such manner that the installation, operation, and maintenance of such new plant will not impair the ability of the SROG Cities to deliver Effluent pursuant to this Agreement.

11.

PVNGS Priority . The Palo Verde Participants’ right to the delivery of Effluent from the SROG Cities pursuant to this Agreement shall have priority over any other use or sale of Effluent from the 91st Avenue WWTP (“PVNGS Priority”), other than preexisting commitments to Buckeye Irrigation Company (30,000 acre-feet), the Arizona Game & Fish Department (7,300 acre-feet), the United States Water Conservation Lab (1,200 acre-feet), and each of their successors-in-interest (collectively, “Preexisting Users”), and only up to the respective quantities provided herein. Any use of the Committed Quantity by the SROG Cities or any of them and by others claiming by, through, or under the SROG Cities or any of them (other than the Preexisting Users) shall be subordinated to the rights of the Palo Verde Participants pursuant to this Agreement.

12.

Location of Use . Delivered Effluent may be used by the Palo Verde Participants at PVNGS and any other electric generating facilities located within 10 miles of PVNGS. In addition, Effluent discharged from the WRSS Pipeline for purposes of maintaining and repairing the WRSS Pipeline may be used on agricultural lands adjacent to the WRSS Pipeline and/or within the service area of an irrigation or water conservation district formed pursuant to A.R.S. § 48-2901 et seq., as amended.

13.

Use of Effluent . Except as required for maintenance and repair activities on the WRSS Pipeline, Effluent made available to the Palo Verde Participants pursuant to this Agreement shall not be directly or indirectly utilized other than for the purposes stated in this Agreement without prior written consent of the SROG Cities.

14.	Option to Extend and True-Up Payment . In 2035, the Parties shall begin meeting to discuss a potential new agreement for the purchase and sale of Effluent or an extension of this Agreement for an additional 20 years through 2070 with no changes in PVNGS

Priority. The price terms of such new agreement or extended Agreement, which extended Agreement would be applicable for the years 2051 through 2070 only, will be negotiated at that time. If the Parties successfully negotiate a new agreement or an extension of this Agreement, and upon full execution of such new agreement or extended Agreement and approval by the governing bodies of all of the Parties, the Palo Verde Participants shall pay Phoenix, on behalf of the SROG Cities, a lump-sum true-up payment (“True-Up Payment”) if the annual price adjustment cap of three percent is exceeded during the 2029 through 2035 period. The True-Up Payment shall be based on the actual rate of inflation (based on the Indices Basket) during each year that the three-percent cap was exceeded; provided, however , the total overall price adjustment, including the True-Up Payment, in each year of the 2029 through 2035 period shall not exceed four percent. If the Parties are unable to mutually agree on the terms of a new agreement or an extension of this Agreement, or if such new agreement or extended Agreement is not approved by all of the Parties’ governing bodies, the Palo Verde Participants shall not be obligated to pay a True-Up Payment.

15.

Notice of Unit Shutdown . Subject to Section 27.2, below, in the event the Palo Verde Participants intend to take out of service and permanently retire from use as a source of electric generation a PVNGS electric generating unit, the Palo Verde Participants shall provide Phoenix with at least 24 months’ written notice of the date on which the unit will be shut down.

16.	No Waiver of Water Rights . Nothing in this Agreement shall constitute a waiver, relinquishment, abandonment, or forfeiture of any water rights of any of the Parties.

17.

Easements and Rights-of-Way . Phoenix, without cost to the Palo Verde Participants, shall grant easements, rights-of-way, leases, and licenses to the Palo Verde Participants for all Participants’ Facilities as may be located at the site of the 9lst Avenue WWTP. It shall be the responsibility of Phoenix and APS to agree upon the scope and description of such easements, rights-of-way, leases, and licenses.

18.	Pledge, Transfer, and Assignment of Palo Verde Participants Interest .

18.1. The Palo Verde 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 all or part of their respective interests in this Agreement and in any property installed or maintained subject to this Agreement, including, without limitation, Participants’ Facilities, to a trustee or trustees under deeds, mortgages, or indentures or to a secured party or parties under a security agreement as security for present or future successors or assigns thereof, without need for the prior written consent of any other Palo Verde Participant or the SROG Cities and without such mortgagee, trustee, or secured party assuming or becoming in any respect obligated to perform any obligations under this Agreement.

18.2. Upon 30 days’ advance written notice to the other Palo Verde Participants and the SROG Cities, any mortgagee, trustee, or secured party under present or future deeds of trust, mortgages, indentures, or security agreements of any Palo Verde

Participant and any successor or assign thereof, and any receiver, referee, or trustee in bankruptcy or reorganization of any Palo Verde Participant, and any successor by action of law or otherwise, and any purchaser, transferee, or assignee of any thereof may, without need for the prior written consent of any other Palo Verde Participant or the SROG Cities, succeed to and acquire all the rights, titles, and interests of such Palo Verde Participant in this Agreement and in any property installed or maintained subject to this Agreement and may take over possession of or foreclose upon said rights, titles, and interests of such Palo Verde Participant.

18.3. Upon 30 days’ advance written notice to the SROG Cities and other Palo Verde Participants, each Palo Verde Participant shall have the right to transfer and assign all or part of its interest in this Agreement to any Person who is or will become a Palo Verde Participant without the prior written consent of the SROG Cities or any other Palo Verde Participant. Upon any such transfer, the Palo Verde Participant acquiring such interest shall assume all the duties and obligations related thereto and, with the written consent of the SROG Cities, which shall not be unreasonably withheld, the Palo Verde Participant transferring such interest shall be released and discharged therefrom.

18.4. Except as otherwise provided in Sections 18.1, 18.2, and 18.3, above, any Person succeeding to the rights, titles, and interests of a Palo Verde Participant or SROG City shall assume and agree to fully perform and discharge all of the obligations hereunder of such Palo Verde Participant or SROG City, and such Person or successor shall notify each of the other Palo Verde Participants and the SROG Cities in writing of such transfer, assignment, or merger and shall furnish to each Palo Verde Participant and the SROG Cities evidence of such transfer, assignment, or merger.

18.5. Any Palo Verde Participant or SROG City transferring or assigning any of its rights, titles, or interest in and to this Agreement shall provide 30 days’ advance written notice to each of the other Palo Verde Participants and SROG Cities.

19.

Improvements and Additions . The SROG Cities shall, at their sole expense, take all reasonably practical actions necessary, including, without limitation, making improvements, modifications, and additions to the 91st Avenue WWTP, to ensure compliance with the delivery quantities established in Section 3 and quality standards set forth in Section 7 hereof. If the SROG Cities fail, refuse, or are unable to make required improvements, modifications, and additions, the Palo Verde Participants shall have the right, with the concurrence of the SROG Cities, which concurrence shall not unreasonably be withheld, to install any facilities necessary to provide the treatment of Effluent required to meet such quality specifications, and payments required to be made by the Palo Verde Participants pursuant to Section 4, above, shall be reduced by the amount of all costs reasonably incurred by the Palo Verde Participants to install, operate, and maintain such facilities, including reasonable fixed charges and operation and maintenance expenses.

20.	Permits and Authorizations .

20.1. Palo Verde Participants . APS shall be solely responsible for securing and maintaining in force and effect any and all permits and authorizations required by law for the transportation of Effluent from the Delivery Points to PVNGS or to any other points and for any uses of the Effluent set forth in this Agreement. APS shall use the Effluent in accordance with all applicable laws and regulations.

20.2. SROG Cities . The SROG Cities shall be solely responsible for securing and maintaining in force and effect any and all permits and authorizations required by law for the delivery of Effluent to the Palo Verde Participants at the Delivery Points and for the discharge into any watercourse or other disposal of Effluent that is not delivered to and accepted by the Palo Verde Participants pursuant to this Agreement. The SROG Cities shall deliver the Effluent to the Palo Verde Participants in accordance with all applicable laws and regulations.

20.3. Section 27.2, below, notwithstanding, if any laws or regulations governing the delivery or use of Effluent as contemplated under this Agreement are promulgated in the future so as to make it impossible or infeasible to deliver and use the Effluent as specified hereunder, the Parties shall meet to discuss in good faith how the purposes of this Agreement and intent of the Parties may be effectuated in accordance with such newly promulgated laws or regulations.

21.	Destruction, Damage, or Condemnation .

21.1. If all, or any part, of the 91st Avenue WWTP is destroyed, damaged, or condemned, the SROG Cities shall restore or reconstruct the 91st Avenue WWTP in such a manner as to permit the SROG Cities to deliver Effluent to the Palo Verde Participants pursuant to this Agreement; or in the event substitute wastewater treatment facilities are constructed at a new location other than the site of the 91st Avenue WWTP, in lieu of restoration or reconstruction of the 91st Avenue WWTP, the SROG Cities shall sell and deliver the same rights to the treated wastewater from such substitute facilities on the same terms and conditions as apply to the sale and delivery of Effluent from the 91 st Avenue WWTP pursuant to this Agreement. If the SROG Cities make changes to the 91 st Avenue WWTP or construct substitute wastewater treatment facilities at a new location pursuant to this Section 21.1, the SROG Cities shall, at their sole expense, design, construct, and install all infrastructure necessary to deliver the Effluent pursuant to this Agreement.

21.2. If all or a portion of the Participants’ Facilities are destroyed or condemned, the Palo Verde Participants shall repair, restore, or reconstruct the Participants’ Facilities in a manner to permit the Palo Verde Participants to receive and transport Effluent pursuant to this Agreement.

22.

Taxes .

22.1. If any general and/or special city, county, state, or other real property taxes, or any other typical taxes or imposts are properly assessed or levied against the Participants’ Facilities, the Palo Verde Participants shall pay all such taxes prior to delinquency.

22.2. If any general and/or special county, state, or federal (but not city) taxes are properly assessed or levied against the purchase or use of Effluent pursuant to this Agreement, the Palo Verde Participants shall pay all such taxes prior to delinquency.

22.3. The SROG Cities or any of them shall not require the Palo Verde Participants to pay a tax resulting from the sale of Effluent by the SROG Cities or impose any assessment on the Participants’ Facilities. If, contrary to this Section 22.3, the SROG Cities or any of them imposes an assessment or levies a tax on the Participants’ Facilities that has the effect of raising the price of Effluent under this Agreement, the price of Effluent shall be decreased by the amount of such tax or assessment.

22.4. If any general and/or special city, county, state, or other real property taxes, or any other type of taxes or imposts are assessed or levied against the 91 st Ave WWTP, the SROG Cities shall pay all such taxes prior to delinquency.

22.5. Nothing contained in this Section 22 shall be construed as a recognition or admission by the SROG Cities or the Palo Verde Participants of the validity of any particular tax or assessment.

23.	Liability, Indemnification, and Insurance .

23.1. Liability of SROG Cities . Except for the negligence or willful misconduct of the Palo Verde Participants, their officers, directors, employees, and agents, the SROG Cities shall be liable insofar as the Palo Verde Participants are concerned for any physical damage to property and death of, and personal injury to, anyone arising out of the ownership, use, occupancy, operation, maintenance, repair, replacement, and reconstruction of the 9lst Avenue WWTP; and the SROG Cities hereby indemnify and hold the Palo Verde Participants harmless for, from, and against any cost, expense, claim, or loss from such damage or injury.

23.2. Liability of Palo Verde Participants . Except for the negligence or willful misconduct of the SROG Cities, their officers, councilmembers, managers, employees, or agents, the Palo Verde Participants shall be liable insofar as the SROG Cities are concerned for any physical damage to property and death of, and personal injury to, anyone arising out of the Palo Verde Participants’ ownership, use, occupancy, operation, maintenance, repair, replacement, and reconstruction of the Participants’ Facilities; and the Palo Verde Participants hereby indemnify

and hold the SROG Cities harmless for, from, and against any cost, expense, claim, or loss from such damage or injury.

23.3. Indemnification for Use of Delivered Effluent . The Palo Verde Participants shall indemnify the SROG Cities for, from, and against any claim resulting from the control, transmission, use, or disposal of Effluent by the Palo Verde Participants after delivery thereof by the SROG Cities to the Delivery Points, except to the extent such claim is the result of the SROG Cities’ failure to comply with the quality standards set forth in Section 7.1, above.

23.4. Insurance . The SROG Cities and the Palo Verde Participants shall procure and maintain insurance against physical damage to property and death of, and personal injury to, persons of the kind and with coverages normally carried by entities operating properties similar to the 91st Avenue WWTP and the Participants’ Facilities. Nothing contained in this Section 23.4 shall prohibit the SROG Cities and the Palo Verde Participants from adopting a self-insurance program of a type and kind being utilized by entities operating properties similar to the 91st Avenue WWTP and the Participants’ Facilities. Upon request, the SROG Cities and the Palo Verde Participants shall furnish the others with certifications of insurance demonstrating compliance with this Section 23.4.

24.	Cooperation of the Parties .

24.1. Each of the SROG Cities and the Palo Verde Participants shall fully cooperate with and assist one another in securing and maintaining in force any and all licenses, permits, authorizations, approvals, and consents required in accordance with this Agreement or by local, state, or federal laws and regulations and shall render such assistance to the other Parties as it or they may reasonably request.

24.2. Each of the SROG Cities and the Palo Verde Participants shall fully cooperate with and assist one another in any and all judicial and administrative proceedings required in or related to the performance of this Agreement.

24.3. Each of the SROG Cities and the Palo Verde Participants shall make, execute, and deliver all documents and instruments necessary or useful to the implementation and performance of this Agreement.

24.4. In the event any proceeding at law or equity is instituted involving the authority and power of any of the SROG Cities and/or the Palo Verde Participants to make, execute, and deliver this Agreement and/or to perform its terms, covenants, and conditions, or is relating to the rights, title, and interest of any of the SROG Cities or the Palo Verde Participants in and to Effluent, then the SROG Cities and the Palo Verde Participants shall jointly and cooperatively defend the validity of this Agreement and the use of Effluent intended hereunder.

25.	Interruption of Delivery of Effluent .

25.1. Subject to Section 25.2 below, the SROG Cities shall have the right to refuse to deliver Effluent under the terms of this Agreement when all of the following have occurred: (i) there exists in the SROG Cities a critical need for water to be used for domestic purposes; (ii) subject to Section 11, above, all other reasonable sources of water in excess of the Committed Quantity have been exhausted; (iii) reasonable steps have been taken by the SROG Cities to conserve their municipal water supplies; and (iv) the SROG Cities have given the Palo Verde Participants reasonable notice of the critical need in accordance with the requirements of Section 28.3, below. When the critical need expires, or when other reasonable sources of water become available, the SROG Cities may no longer refuse to deliver Effluent pursuant to this Agreement. The SROG Cities shall use their best efforts to resume deliveries of Effluent pursuant to this Agreement at the earliest practicable time if such deliveries are interrupted pursuant to this Section 25.

25.2. Prior to designating the existence of a critical need and temporarily discontinuing Effluent deliveries to the Palo Verde Participants pursuant to Section 25.1, above, the SROG Cities shall consider the critical need for energy to support the Parties’ respective customer bases by expressly acknowledging the symbiotic relationship between water and energy in the desert state of Arizona and the interdependency of these two vital resources by taking into account the mutual critical need each Party has for the other’s product.

26.	Dispute Resolution; Default and Termination .

26.1. In the event of a dispute arising out of or relating to this Agreement, the Parties shall attempt in good faith to resolve such dispute promptly by negotiation between representatives having authority to settle the controversy. All reasonable requests for information made by one Party to the other shall be honored.

26.2. The Parties shall pay all monies and carry out all other performances, duties, and obligations agreed to be paid and/or performed by them pursuant to the terms and conditions set forth and contained in this Agreement. A default by a Party in its covenants and obligations shall be an act of default under this Agreement (“Default”).

26.3. In the event of a Default by a Party, within 30 days following the giving of written notice of such Default by the non-defaulting Party, the defaulting Party shall remedy such Default either by advancing the necessary funds and/or rendering the necessary performance, as the context so requires. The notice required by this Section 26.3 shall clearly identify the specific nature of the Default and the steps required to cure the same.

26.4. In the event that a Party disputes an asserted Default, such Party shall pay the disputed payment or perform the disputed obligation, but may do so under protest, which protest shall be in writing, shall accompany the disputed payment or

precede the performance of the disputed obligation, and shall specify the reasons upon which the protest is based. Payments not made under protest shall be deemed to be correct.

26.5. In the event of a Default by a Party in the payment or performance of any obligation under this Agreement, which continues for a period of 60 days or more without having been cured by the defaulting Party, or without the defaulting Party having commenced or continued action in good faith to cure such Default, then, at any time thereafter and while said Default is continuing, the non-defaulting Party at its option may, by written notice to the defaulting Party, terminate this Agreement.

26.6. If this Agreement is terminated for any reason, Phoenix shall have the immediate right of re-entry of any easement or leasehold granted to the Palo Verde Participants pursuant to Section 17, above. APS shall, as soon as reasonably practicable or within such other time frame as the Parties may agree, remove all facilities owned by the Palo Verde Participants located on property owned by the SROG Cities or any of them. All facilities not removed from such property within such time frame shall become the property of the owner of such real property.

27.	Performance and Uncontrollable Circumstance .

27.1. Performance . All terms, covenants, and conditions to be performed by the Parties under this Agreement shall be performed at the sole expense of the Party so obligated, and if another Party pays any sum of money or does any act that requires the payment of money, by reason of the failure, neglect, or refusal of the obligated Party to perform such term, covenant, or condition, the sum of money so paid by the other Party shall immediately be payable to the non-obligated Party by the Party obligated to perform.

27.2. Uncontrollable Circumstance . A Party shall not be considered to be in Default in the performance of any of the obligations under this Agreement (other than obligations of a Party to pay costs and expenses) if failure of performance is due to an Uncontrollable Circumstance. The term “Uncontrollable Circumstance” means any act, event, or condition that is caused by or due to circumstances beyond the reasonable control of the Party relying thereon as justification for not performing an obligation or complying with any condition required of such Party under this Agreement and that materially interferes with such Party’s obligations under this Agreement (other than payment obligations) to the extent that such act, event, or condition is not the result of the willful or negligent act, error or omission, failure to exercise reasonable diligence, or breach of this Agreement on the part of such Party. By way of example, but not limitation, each of the following shall constitute an Uncontrollable Circumstance: failure of facilities, flood, earthquake, tornado, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, action or non-action by or failure to obtain the necessary authorizations or approvals from any governmental agency

or authority or the electorate, labor or material shortage, sabotage, restraint by court order, law, regulation, or public authority, and the forced shutdown of PVNGS or the 91 st Avenue WWTP by a governmental body, 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 in this Section 28.2 shall be construed so as to require a Party to settle any strike or labor dispute in which it may be involved. A Party rendered unable to fulfill any obligation by reason of an Uncontrollable Circumstance shall, as soon as reasonably practicable, notify the others of the event giving rise to such Uncontrollable Circumstance, and exercise due diligence to remove such inability with all reasonable dispatch.

28.	General Provisions .

28.1. Incorporation of Recitals and Exhibit . The Recitals set forth in Paragraphs A through K, above, and Exhibit “A” attached to this Agreement (but not the attached Appendix) are incorporated here by this reference as if fully set forth in this Agreement, and are acknowledged and agreed to by the Parties.

28.2. Case; Section Headings . The use of the singular or plural number shall be deemed to include the other uses whenever the context so requires. The section headings used in this Agreement are for convenience and reference only and do not define, limit, or describe the scope or intent of any provision of this Agreement.

28.3. Notices . Notices shall be in writing and shall be given by: (a) personal delivery; (b) national overnight delivery service; or (c) United States Mail, certified mail, return receipt requested, postage prepaid. Notices shall be delivered or addressed to the addresses set forth below or at such other address as APS or Phoenix may designate in writing. The date a notice shall be deemed to have been given, received, and become effective shall be: (i) the date on which the notice is delivered or refused, if notice is given by personal delivery or delivery by a national overnight delivery service; or (ii) three days following the date of deposit in the mail, if the notice is sent by certified United States Mail, return receipt requested and postage prepaid. No notice shall be deemed effective unless sent in one of the manners described above.

To Phoenix: Director of Water Services

City of Phoenix

200 West Washington Street

Phoenix, Arizona 85003

To PVNGS: Palo Verde Nuclear Generating Station

Att’n: Water Reclamation Facility Manager

5801 South Wintersburg Road, M.S. 6215

Tonopah, Arizona 85354-7529

with a copy to APS: Arizona Public Service Company

Att’n: Water Resources Manager

P.O. Box 52034, M.S. 9724

Phoenix, Arizona 85072-2034

Any Party referenced in this Section 28.3 may change the address or addressee to which notices are to be sent by giving notice of such change of address or addressee in conformity with the provisions of this Section 28.3.

28.4. Remedies Cumulative . The remedies provided for in this Agreement shall be cumulative. All remedies available under this Agreement shall be in addition to any and all remedies at law or in equity.

28.5. Successors and Assigns . The terms, covenants, and conditions of this Agreement shall be binding upon, and inure to the benefit of and shall apply to the respective transferees, successors, and assigns of the transferring Party.

28.6. Governing Law . This Agreement shall be governed by, and construed in accordance with, the laws of the State of Arizona.

28.7. Entire Agreement . The Parties expressly acknowledge that they have read this Agreement and understand all of its terms, covenants, and conditions, and that this Agreement constitutes the entire agreement with respect to any matters referred to in this Agreement. This Agreement supersedes any and all other understandings, agreements, correspondence, or communications between the Parties with respect to the matters embodied in this Agreement, including Agreement No. 13904, which shall be of no further force and effect.

28.8. Modification . No changes, alterations, or modifications to this Agreement shall be effective unless in writing and signed by an authorized representative of each of the Parties.

28.9. Waiver . The failure of a Party to insist, in any one or more instances, on performance of any of the terms, covenants, or conditions of this Agreement shall not be construed as a waiver or relinquishment of any rights granted under this Agreement or of the future performance of any such term, covenant, or condition, and the obligations of the Parties with respect thereto shall continue in full force and effect. No waiver of any provision or condition of this Agreement by a Party shall be valid unless in writing signed by such Party. A waiver by one Party of the performance of any covenant or condition of another Party shall not invalidate this Agreement, nor shall such waiver be construed as a waiver of any other covenant or condition.

28.10. No Party the Drafter . This Agreement is the product of negotiation between the Parties, and no Party is deemed the drafter of this Agreement.

28.11. Conflict of Interest . The provisions of A.R.S. § 38-511 are incorporated in this Agreement to the extent of their applicability to contracts of the nature of this Agreement under the laws of the State of Arizona.

28.12. Counterpart Execution . This Agreement may be signed in counterparts, each of which shall be an original and all of which shall constitute one and the same instrument. All signatures need not be on the same counterpart.

28.13. Authorizations . The signatories to this Agreement represent that they have been appropriately authorized to enter into this Agreement on behalf of the Party for which they sign and that no further action or approvals are necessary before execution of this Agreement.

IN WITNESS WHEREOF, the Parties have executed this Agreement as of _________________ ____, 2010.

[Remainder of page intentionally left blank]

CITY OF PHOENIX,

an Arizona municipal corporation

By: /s/ David Cavazoa

Its: City Manager

Attest:

/s/ Mario Paniagua

City Clerk

Approved as to Form:

/s/ Gary Verburg

Acting Phoenix City Attorney

STATE OF ARIZONA )

)ss.

County of Maricopa )

On April, 14 2010, before me, Dawnell M. Navarro , a Notary Public in and for the State of Arizona, personally appeared David Cavazos , personally known to me (or proved to me on the basis of satisfactory evidence) to be the City Manager and _________________ of the CITY OF PHOENIX, an Arizona municipal corporation, and that they being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the municipal corporation by themselves and as such _________________ and _________________.

WITNESS my hand and official seal.

/s/ Dawnell M. Navarro

Notary Public

My Commission Expires:

(SEAL)

March 30, 2013

CITY OF MESA,

an Arizona municipal corporation

By: / s/ Christopher J. Brady

Its: City Manager

Attest:

/s/ Linda Crocker

City Clerk

Approved as to Form:

/s/ Wilbert J. Taebel

Mesa City Attorney

STATE OF ARIZONA )

)ss.

County of Maricopa )

On April, 29 2010, before me, Ann Webster , a Notary Public in and for the State of Arizona, personally appeared Christopher J. Brady , personally known to me (or proved to me on the basis of satisfactory evidence) to be the City Manager and _________________ of the CITY OF MESA, an Arizona municipal corporation, and that they being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the municipal corporation by themselves and as such City Manager and _________________.

WITNESS my hand and official seal.

/s/ Ann Webster

Notary Public

My Commission Expires:

May 27, 2010 (SEAL)

CITY OF TEMPE,

an Arizona municipal corporation

By: /s / Hugh Hallman

Its: Mayor

Attest:

/s/ Jan Hort

City Clerk

Approved as to Form:

/s/ Andrew B. Ching

Tempe City Attorney

STATE OF ARIZONA )

)ss.

County of Maricopa )

On April 26, ___ 2010, before me, Kay Savard , a Notary Public in and for the State of Arizona, personally appeared Hugh Hallman & Jan Hort , personally known to me (or proved to me on the basis of satisfactory evidence) to be the Mayor and City Clerk of the CITY OF TEMPE, an Arizona municipal corporation, and that they being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the municipal corporation by themselves and as such _________________ and _________________.

WITNESS my hand and official seal.

/s/ Kay E. Savard

Notary Public

My Commission Expires:

Aug. 20, 2013

(SEAL)

CITY OF SCOTTSDALE,

an Arizona municipal corporation

By: /s/ W. J. Lane

Its: M ayor

Attest:

/s/ Carolyn Jagger

City Clerk

Approved as to Form:

/s/ Steven B. Bennett

Scottsdale City Attorney

STATE OF ARIZONA )

)ss.

County of Maricopa )

On April, 19 2010, before me, K. Stevens , a Notary Public in and for the State of Arizona, personally appeared Jim Lane and Carolyn Jagger , personally known to me (or proved to me on the basis of satisfactory evidence) to be the Mayor and City Clerk of the CITY OF SCOTTSDALE, an Arizona municipal corporation, and that they being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the municipal corporation by themselves and as such Mayor and City Clerk .

WITNESS my hand and official seal.

/s/ K. Stevens

Notary Public

My Commission Expires: (SEAL)

Nov. 28, 2013

CITY OF GLENDALE,

an Arizona municipal corporation

By: /a / Pamela J. Kavanaugh

Its: Assistant City Manager

Attest:

/a/ Pamela Hanna

City Clerk

Approved as to Form:

/s/ Craig D. Tindall

Glendale City Attorney

STATE OF ARIZONA )

)ss.

County of Maricopa )

On April, 16 2010, before me, Summer Steinke , a Notary Public in and for the State of Arizona, personally appeared Pam Kavanaugh , personally known to me (or proved to me on the basis of satisfactory evidence) to be the Assistant City Manager of the CITY OF GLENDALE, an Arizona municipal corporation, and that they being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the municipal corporation by themselves and as such Assistant City Manager .

WITNESS my hand and official seal.

/s/ Summer Steinke

Notary Public

My Commission Expires: (SEAL)

1/9/2011

ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation

By: / s/ Randall K. Edington

Its: EVP & CNO

Attest:

/s/ Diane Wood

STATE OF ARIZONA )

)ss.

County of Maricopa )

On April, 23 2010, before me, Barbara J. Dubishar , a Notary Public in and for the State of Arizona, personally appeared Randall K. Edington AND Diane Wood , personally known to me (or proved to me on the basis of satisfactory evidence) to be the EVP & CNO and Associate Secretary of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, and that they being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the municipal (BJD) corporation by themselves and as such EVP & CNO and Associate Secretary .

WITNESS my hand and official seal.

/s/ Barbara J. Dubishar

Notary Public

My Commission Expires:

December 12, 2010

(SEAL)

SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an Arizona municipal corporation and agricultural improvement district

By: /s/ Jo hn M. Williams, Jr.

Its: President

Attest and Countersign:

/s/ Terrill A. Lonon

Approved as to Form:

/s/ Frederic L. Beeson

STATE OF ARIZONA )

)ss.

County of Maricopa )

On March, 26, 2010, before me, Fay A. Wehofer , a Notary Public in and for the State of Arizona, personally appeared John M. Williams Jr, and Terrill A. Lonon , personally known to me (or proved to me on the basis of satisfactory evidence) to be the President and Secretary of the SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT, an Arizona municipal corporation and agricultural improvement district, and that they being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the municipal corporation by themselves and as such President and Secretary .

WITNESS my hand and official seal.

(SEAL)

/s/ Fay A. Wehofer

Notary Public

My Commission Expires:

11/27/2011

EXHIBIT “A”

Map of Delivery Points

A map depicting the delivery points interconnecting the 91 st Avenue WWTP with the PVNGS water reclamation supply system pipeline for transport to the PVNGS Water Reclamation Facility.

APPENDIX †

Examples of Non-Usage Fee Calculations under

Municipal Effluent Purchase and Sale Agreement

For purposes of this Appendix, a Committed Quantity of 80,000 acre-feet (AF) is assumed. In addition, this Appendix assumes the following for the years 2028 and 2029:

2028

Delivered Effluent Quantity: 65,000 AF

Per Acre-Foot Price:

Tier 1 – $198.00

Tier 2 – $293.00

Tier 3 – $349.00

Tier 4 – $474.00

Average Per-Acre-Foot Price: $328.50 [($198.00 + $293.00 + $349.00 + $474.00) ÷ 4]

Outage Periods and Effluent Usage

Unit 1 outage: May 1 through August 31 = 123 days

Unit 2 Effluent usage from May 1 through August 31: 8,220 AF

Unit 3 Effluent usage from May 1 through August 31: 8,230 AF

Unit 3 outage: November 16 through December 31 = 45 days (outage ongoing into 2029)

Unit 1 Effluent usage from November 16 through December 31: 2,318 AF

Unit 2 Effluent usage from November 16 through December 31: 2,316 AF

2029

Delivered Effluent Quantity: 72,500 AF

Per Acre-Foot Price:

Tier 1 – $203.94

Tier 2 – $301.79

Tier 3 – $359.47

Tier 4 – $488.22

Average Per-Acre-Foot Price: $338.36 [(203.94 + 301.79 + 359.47 + 488.22) ÷ 4]

Outage Period and Effluent Usage

Unit 3 outage: January 1 through February 28 = 59 days (outage continuing from 2028)

Unit 1 Effluent usage from January 1 through February 28: 3,040 AF

Unit 2 Effluent usage from January 1 through February 28: 3,036 AF

† This Appendix is for illustrative purposes only and is neither incorporated into nor made a part of the Municipal Effluent Purchase and Sale Agreement. Capitalized terms used in this Appendix shall have the meanings ascribed to them in the Municipal Effluent Purchase and Sale Agreement.

In 2028, the Unit 1 outage lasted for a total of 123 days. Therefore, pursuant to Section 5.1.3.1, it is an Extended Outage Period. Based on the totalizer readings taken pursuant to Section 5.1.3.3, pursuant to Section 5.1.3.2, the Representative Usage for the Unit 1 Extended Outage Period would be calculated by taking the average Effluent usage of the two remaining PVNGS electric generating units operating at full power ( i.e. , Units 2 and 3) over that same period, or 8,225 AF [(8,220 AF + 8,230 AF) ÷ 2]. In 2028, Unit 3 was also in an outage that commenced on November 16 and continued through the end of that year. However, because only 45 days had passed, the outage was not treated as an Extended Outage Period and, as a result, the Palo Verde Participants paid the higher 30 percent Non-Usage Fee on that portion of the outage extending from November 16 through December 31.

Pursuant to Sections 5.1.3.4 and 5.2, by January 31, 2029, the Palo Verde Participants would pay Phoenix, on behalf of the SROG Cities, a Non-Usage Fee of $1,208,058.75 calculated as follows:

Portion of 2028 Non-Usage Fee Payable over Extended Outage Period

$540,382.50 [8,225 AF x $328.50 x .20]

Portion of 2028 Non-Usage Fee Payable over Non-Extended Outage Period

$667,676.25 [(80,000 AF – 65,000 AF – 8,225 AF) x $328.50 x .30]

Total 2028 Non-Usage Fee: $540,382.50 + $667,676.25 = $1,208,058.75

______________________________________________

In 2029, there was only one outage—an outage to Unit 3, which was a continuation of the outage that commenced on November 16, 2028. Because the outage lasted 104 days until Unit 3 resumed full power on February 28, 2029, it constituted an Extended Outage Period. The Representative Usage for that portion of the Unit 3 Extended Outage Period occurring from January 1, 2029 through February 28, 2029 would be calculated by taking the average Effluent usage of the two remaining PVNGS electric generating units operating at full power ( i.e. , Units 1 and 2) over that same period, or 3,038 AF [(3,040 AF + 3,036 AF) ÷ 2].

Because that portion of the Unit 3 outage extending from November 16 through December 31, 2028 was not treated as an Extended Outage Period (because the existence of such Extended Outage Period was unknown as of December 31 of that year), the Palo Verde Participants paid the higher 30 percent Non-Usage Fee for that 45-day period. Therefore, pursuant to Section 5.1.3.6, 10 percent of that portion of the Non-Usage Fee attributable to that part of the Extended Outage Period extending from November 16 through December 31, 2028 must be credited against the Non-Usage Fee payable in 2029. To determine the amount of the credit, the Representative Usage for that portion of the Unit 3 Extended Outage Period occurring from November 16, 2028 through December 31, 2028 must be calculated by taking the average Effluent usage of the two remaining PVNGS electric generating units operating at full power ( i.e. , Units 1 and 2) over that same period, or 2,317 AF [(2,318 AF + 2,316 AF) ÷ 2].

By January 31, 2030, the Palo Verde Participants would pay Phoenix, on behalf of the SROG Cities, a Non-Usage Fee of $582,402.79 calculated as follows:

Portion of 2029 Non-Usage Fee Payable over Extended Outage Period

$205,587.54 [3,038 AF x $338.36 x .20]

Portion of 2029 Non-Usage Fee Payable over Non-Extended Outage Period

$452,928.70 [(80,000 AF – 72,500 AF – 3,038 AF) x $338.36 x .30]

Credit for that Portion of Extended Outage Period Occurring in 2028

$76,113.45 [2,317 AF x $328.50 x .10]

Total 2029 Non-Usage Fee: $205,587.54 + $452,928.70 – $76,113.45 = $582,402.79

Exhibit 12.1

PNM RESOURCES, INC. AND SUBSIDIARIES
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)


	Three Months Ended			Year Ended December 31,
	March 31, 2010			2009			2008			2007			2006
Fixed charges, as defined by the Securities and Exchange
Commission:

Interest expensed and capitalized	$	31,306		$	123,833		$	134,958		$	124,299		$	135,819
Amortization of debt premium, discount and expenses		1,178			5,430			6,386			6,566			4,729
Interest from discontinued operations (including capitalized interest)		-			1,027			13,758			12,546			11,790
Estimated interest factor of lease rental charges		1,384			7,034			7,894			8,804			7,124
Preferred dividend requirements of subsidiary		257			759			689			556			798
Total Fixed Charges	$	34,125		$	138,083		$	163,685		$	152,771		$	160,260



Earnings, as defined by the Securities and Exchange
Commission:

Earnings from continuing operations before income taxes and non-controlling interest	$	(10,153	)	$	94,751		$	(388,381	)	$	63,112		$	164,018
(Earnings) loss of equity investee		4,352			30,145			29,687			(7,581	)		-
Earnings from continuing operations before income taxes, non-controlling interest, and investee earnings		(5,801	)		124,896			(358,694	)		55,531			164,018
Fixed charges as above		34,125			138,083			163,685			152,771			160,260
Interest capitalized		(1,186	)		(7,743	)		(8,849	)		(10,740	)		(6,503	)
Non-controlling interest in earnings of Valencia		(3,103	)		(11,890	)		(7,179	)		-			-
Preferred dividend requirements of subsidiary		(257	)		(759	)		(689	)		(556	)		(798	)

Earnings Available for Fixed Charges	$	23,778		$	242,587		$	(211,726	)	$	197,006		$	316,977

Ratio of Earnings to Fixed Charges		0.70	*		1.76			N/M	*		1.29			1.98

* The ratio of earnings to fixed charges for the year ended December 31, 2008 is not meaningful since earnings available for fixed charges is negative. The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $10.3 million for the three months ended March 31, 2010 and $375.4 million for the year ended December 31, 2008.

Exhibit 12.2

PUBLIC SERVICE COMPANY OF NEW MEXICO
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)


	Three Months Ended			Year Ended December 31,
	March 31, 2010			2009			2008			2007			2006
Fixed charges, as defined by the Securities and Exchange
Commission:

Interest expensed and capitalized	$	18,647		$	73,104		$	72,427		$	58,045		$	49,379
Amortization of debt premium, discount and expenses		334			1,336			4,345			4,618			2,871
Interest from discontinued operations (including capitalized interest)		-			1,027			13,758			12,546			11,790
Estimated interest factor of lease rental charges		905			4,517			4,553			4,661			4,337
Total Fixed Charges	$	19,886		$	79,984		$	95,083		$	79,870		$	68,377

Earnings, as defined by the Securities and Exchange
Commission:

Earnings from continuing operations before income taxes and non-controlling interest	$	10,472		$	45,627		$	(69,324	)	$	34,611		$	89,657
Fixed charges as above		19,886			79,984			95,083			79,870			68,377
Non-controlling interest in earnings of Valencia		(3,103	)		(11,890	)		(7,179	)		-			-
Interest capitalized		(1,016	)		(6,067	)		(7,363	)		(10,033	)		(5,257	)

Earnings Available for Fixed Charges	$	26,239		$	107,654		$	11,217		$	104,448		$	152,777

Ratio of Earnings to Fixed Charges		1.32			1.35			0.12	*		1.31			2.23

* The shortfall in the earnings available for fixed charges to achieve a ratio of earnings to fixed charges of 1.00 amounted to $83.9 million for the year December 31, 2008

Exhibit 12.3

TEXAS-NEW MEXICO POWER COMPANY
Ratio of Earnings to Fixed Charges
(In thousands, except ratio)


	Three Months Ended			Year Ended December 31,
	March 31, 2010			2009			2008			2007			2006
Fixed charges, as defined by the Securities and Exchange
Commission:

Interest expensed and capitalized	$	7,211		$	25,609		$	17,861		$	23,523		$	27,374
Amortization of debt premium, discount and expenses		683			3,355			1,504			1,925			1,695
Estimated interest factor of lease rental charges		147			831			571			844			367

Total Fixed Charges	$	8,041		$	29,795		$	19,936		$	26,292		$	29,436


Earnings, as defined by the Securities and Exchange
Commission:

Earnings from continuing operations before income taxes	$	2,719		$	20,151		$	2,335		$	29,055		$	17,905
Fixed charges as above		8,041			29,795			19,936			26,292			29,436
Interest capitalized		(25	)		(1,144	)		(1,025	)		(332	)		(209	)

Earnings Available for Fixed Charges	$	10,735		$	48,802		$	21,246		$	55,015		$	47,132

Ratio of Earnings to Fixed Charges		1.34			1.64			1.07			2.09			1.60

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;

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:

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;

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

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: May 7, 2010

/s/ Patricia K. Collawn

Patricia K. Collawn

President and Chief Executive Officer

PNM Resources, Inc.

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;

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

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: May 7, 2010

/s/ Charles N. Eldred

Charles N. Eldred

Executive Vice President and

Chief Financial Officer

PNM Resources, Inc.

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;

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

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: May 7, 2010

/s/ Patricia K. Collawn

Patricia K. Collawn

President and Chief Executive Officer

Public Service Company of New Mexico

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;

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

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: May 7, 2010

/s/ Charles N. Eldred

Charles N. Eldred

Executive Vice President and

Chief Financial Officer

Public Service Company of New Mexico

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;

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary in order 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;

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

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 (the 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: May 7, 2010

/s/ Patricia K. Collawn

Patricia K. Collawn

President and Chief Executive Officer

Texas-New Mexico Power Company

EXHIBIT 31.6

CERTIFICATION

I, Thomas G. Sategna, certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Texas-New Mexico Power Company;

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;

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

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: May 7, 2010

/s/ Thomas G. Sategna

Thomas G. Sategna

Vice President and Controller

Texas-New Mexico Power Company

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 March 31, 2010, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on May 7, 2010 (“Report”), I, Patricia K. Collawn, President and Chief Executive Officer of the Company, certify 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: May 7, 2010	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		PNM Resources, Inc.

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 March 31, 2010, for PNM Resources, Inc. (“Company”), as filed with the Securities and Exchange Commission on May 7, 2010 (“Report”), I, Charles N. Eldred, Executive Vice President and Chief Financial Officer of the Company, certify 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: May 7, 2010	By:	/s/ Charles N. Eldred
		Charles N. Eldred
		Executive Vice President and
		Chief Financial Officer
		PNM Resources, Inc.

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 March 31, 2010, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on May 7, 2010 (“Report”), I, Patricia K. Collawn, President and Chief Executive Officer of the Company, certify 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: May 7, 2010	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		Public Service Company of New Mexico

EXHIBIT 32.4

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 March 31, 2010, for Public Service Company of New Mexico (“Company”), as filed with the Securities and Exchange Commission on May 7, 2010 (“Report”), I, Charles N. Eldred, Executive Vice President and Chief Financial Officer of the Company, certify 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: May 7, 2010	By:	/s/ Charles N. Eldred
		Charles N. Eldred
		Executive Vice President and
		Chief Financial Officer
		Public Service Company of New Mexico

EXHIBIT 32.5

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 March 31, 2010, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on May 7, 2010 (“Report”), I, Patricia K. Collawn, President and Chief Executive Officer of the Company, certify 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: May 7, 2010	By:	/s/ Patricia K. Collawn
		Patricia K. Collawn
		President and Chief Executive Officer
		Texas-New Mexico Power Company

EXHIBIT 32.6

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 March 31, 2010, for Texas-New Mexico Power Company (“Company”), as filed with the Securities and Exchange Commission on May 7, 2010 (“Report”), I, Thomas G. Sategna, Vice President, Controller of the Company, certify 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: May 7, 2010	By:	/s/ Thomas G. Sategna
		Thomas G. Sategna
		Vice President, Controller
		Texas-New Mexico Power Company