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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 June 30, 2014

 

OR

 

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from              to          

 

Commission File Number		Exact Name of Each Registrant as specified in its charter; State of Incorporation; Address; and Telephone Number		IRS Employer Identification No.
1-8962		PINNACLE WEST CAPITAL CORPORATION (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona  85072-3999 (602) 250-1000		86-0512431
1-4473		ARIZONA PUBLIC SERVICE COMPANY (an Arizona corporation) 400 North Fifth Street, P.O. Box 53999 Phoenix, Arizona  85072-3999 (602) 250-1000		86-0011170

 

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

 

PINNACLE WEST CAPITAL CORPORATION	Yes   x    No  o
ARIZONA PUBLIC SERVICE COMPANY	Yes   x    No  o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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).

 

PINNACLE WEST CAPITAL CORPORATION	Yes   x    No  o
ARIZONA PUBLIC SERVICE COMPANY	Yes   x    No  o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

PINNACLE WEST CAPITAL CORPORATION

 

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

 

ARIZONA PUBLIC SERVICE COMPANY

 

Large accelerated filer o

Accelerated filer o

Non-accelerated filer x

Smaller reporting company o

 

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

PINNACLE WEST CAPITAL CORPORATION	Yes   o    No  x
ARIZONA PUBLIC SERVICE COMPANY	Yes   o    No  x

 

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

 

PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of July 25, 2014: 110,408,854
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of July 25, 2014: 71,264,947

 

Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this form with the reduced disclosure format allowed under that General Instruction.

 

 

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TABLE OF CONTENTS

 

			Page
Forward-Looking Statements			2
Part I			3
Item 1.	Financial Statements		3
	Pinnacle West Capital Corporation		3
	Arizona Public Service Company		47
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		58
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		79
Item 4.	Controls and Procedures		79
Part II			80
Item 1.	Legal Proceedings		80
Item 1A.	Risk Factors		80
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		80
Item 5.	Other Information		81
Item 6.	Exhibits		84
Signatures			87

 

This combined Form 10-Q is separately provided by Pinnacle West Capital Corporation (“Pinnacle West”) and Arizona Public Service Company (“APS”).  Any use of the words “Company,” “we,” and “our” refer to Pinnacle West.  Each registrant is providing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries.  Except as stated in the preceding sentence, neither registrant is providing any information that does not relate to such registrant, and therefore makes no representation as to any such information.  The information required with respect to each company is set forth within the applicable items.  Item 1 of this report includes Condensed Consolidated Financial Statements of Pinnacle West and Condensed Consolidated Financial Statements of APS.  Item 1 also includes Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS, and Supplemental Notes, which only relate to APS’s Condensed Consolidated Financial Statements.

 

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FORWARD-LOOKING STATEMENTS

 

This document contains forward-looking statements based on current expectations.  These forward-looking statements are often identified by words such as “estimate,” “predict,” “may,” “believe,” “plan,” “expect,” “require,” “intend,” “assume” and similar words.  Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements.  A number of factors could cause future results to differ materially from historical results, or from outcomes currently expected or sought by Pinnacle West or APS.  In addition to the Risk Factors described in Part I, Item 1A of the Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (“2013 Form 10-K”), Part II, Item 1A of this report and in Part I, Item 2 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report, these factors include, but are not limited to:

 

·                               our ability to manage capital expenditures and operations and maintenance costs while maintaining reliability and customer service levels;

·                               variations in demand for electricity, including those due to weather, the general economy, customer and sales growth (or decline), and the effects of energy conservation measures and distributed generation;

·                               power plant and transmission system performance and outages;

·                               competition in retail and wholesale power markets;

·                               regulatory and judicial decisions, developments and proceedings;

·                               new legislation or regulation, including those relating to environmental requirements, nuclear plant operations and potential deregulation of retail electric markets;

·                               fuel and water supply availability;

·                               our ability to achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital;

·                               our ability to meet renewable energy and energy efficiency mandates and recover related costs;

·                               risks inherent in the operation of nuclear facilities, including spent fuel disposal uncertainty;

·                               current and future economic conditions in Arizona, particularly in real estate markets;

·                               the cost of debt and equity capital and the ability to access capital markets when required;

·                               environmental and other concerns surrounding coal-fired generation;

·                               volatile fuel and purchased power costs;

·                               the investment performance of the assets of our nuclear decommissioning trusts, pension, and other postretirement benefit plans and the resulting impact on future funding requirements;

·                               the liquidity of wholesale power markets and the use of derivative contracts in our business;

·                               potential shortfalls in insurance coverage;

·                               new accounting requirements or new interpretations of existing requirements;

·                               generation, transmission and distribution facility and system conditions and operating costs;

·                               the ability to meet the anticipated future need for additional baseload generation and associated transmission facilities in our region;

·                               the willingness or ability of our counterparties, power plant participants and power plant land owners to meet contractual or other obligations or extend the rights for continued power plant operations;

·                               technological developments affecting the electric industry; and

·                               restrictions on dividends or other provisions in our credit agreements and Arizona Corporation Commission (“ACC”) orders.

 

These and other factors are discussed in the Risk Factors described in Part I, Item 1A of our 2013 Form 10-K and in Part II, Item 1A of this report, which readers should review carefully before placing any reliance on our financial statements or disclosures.  Neither Pinnacle West nor APS assumes any obligation to update these statements, even if our internal estimates change, except as required by law.

 

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PART I — FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars and shares in thousands, except per share amounts)

 

		Three Months Ended June 30,
		2014			2013
OPERATING REVENUES		$	906,264		$	915,822
OPERATING EXPENSES
Fuel and purchased power		290,854			277,584
Operations and maintenance		211,222			229,300
Depreciation and amortization		105,150			106,292
Taxes other than income taxes		44,004			40,814
Other expenses		921			2,020
Total		652,151			656,010
OPERATING INCOME		254,113			259,812
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		7,499			6,265
Other income (Note 10)		2,781			469
Other expense (Note 10)		(508		)	(2,234		)
Total		9,772			4,500
INTEREST EXPENSE
Interest charges		51,751			51,307
Allowance for borrowed funds used during construction		(3,790		)	(3,636		)
Total		47,961			47,671
INCOME BEFORE INCOME TAXES		215,924			216,641
INCOME TAXES		74,540			77,043
NET INCOME		141,384			139,598
Less: Net income attributable to noncontrolling interests (Note 6)		8,926			8,391
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	132,458		$	131,207
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		110,565			109,962
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		111,002			110,932
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic		$	1.20		$	1.19
Net income attributable to common shareholders — diluted		$	1.19		$	1.18
DIVIDENDS DECLARED PER SHARE		$	1.14		$	1.09

 

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

 

		Three Months Ended June 30,
		2014			2013
NET INCOME		$	141,384		$	139,598
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $(26) and $105		40			(160		)
Reclassification of net realized loss, net of tax benefit of $1,261 and $2,824		1,955			4,322
Pension and other postretirement benefits activity, net of tax benefit of $845 and $449		(1,310		)	(688		)
Total other comprehensive income		685			3,474
COMPREHENSIVE INCOME		142,069			143,072
Less: Comprehensive income attributable to noncontrolling interests		8,926			8,391
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	133,143		$	134,681

 

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(unaudited)

(dollars and shares in thousands, except per share amounts)

 

		Six Months Ended June 30,
		2014			2013
OPERATING REVENUES		$	1,592,515		$	1,602,474
OPERATING EXPENSES
Fuel and purchased power		540,640			508,263
Operations and maintenance		424,104			452,550
Depreciation and amortization		206,922			210,022
Taxes other than income taxes		89,849			80,835
Other expenses		1,717			4,069
Total		1,263,232			1,255,739
OPERATING INCOME		329,283			346,735
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		14,941			13,129
Other income (Note 10)		5,148			1,227
Other expense (Note 10)		(5,192		)	(5,986		)
Total		14,897			8,370
INTEREST EXPENSE
Interest charges		104,720			100,785
Allowance for borrowed funds used during construction		(7,560		)	(7,626		)
Total		97,160			93,159
INCOME BEFORE INCOME TAXES		247,020			261,946
INCOME TAXES		80,945			89,512
NET INCOME		166,075			172,434
Less: Net income attributable to noncontrolling interests (Note 6)		17,851			16,783
NET INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	148,224		$	155,651
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		110,546			109,898
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		110,925			110,843
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Net income attributable to common shareholders — basic		$	1.34		$	1.42
Net income attributable to common shareholders — diluted		$	1.34		$	1.40
DIVIDENDS DECLARED PER SHARE		$	1.14		$	1.09

 

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)

(dollars in thousands)

 

		Six Months Ended June 30,
		2014			2013
NET INCOME		$	166,075		$	172,434
OTHER COMPREHENSIVE INCOME, NET OF TAX
Derivative instruments:
Net unrealized loss, net of tax benefit (expense) of $(624) and $67		(381		)	(102		)
Reclassification of net realized loss, net of tax benefit of $2,584 and $6,124		5,070			9,375
Pension and other postretirement benefits activity, net of tax benefit (expense) of $128 and $(182)		(853		)	278
Total other comprehensive income		3,836			9,551
COMPREHENSIVE INCOME		169,911			181,985
Less: Comprehensive income attributable to noncontrolling interests		17,851			16,783
COMPREHENSIVE INCOME ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	152,060		$	165,202

 

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

 

		June 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	9,161		$	9,526
Customer and other receivables		325,352			299,904
Accrued unbilled revenues		172,444			96,796
Allowance for doubtful accounts		(2,731		)	(3,203		)
Materials and supplies (at average cost)		230,310			221,682
Fossil fuel (at average cost)		38,835			38,028
Deferred income taxes		83,633			91,152
Income tax receivable (Note 5)		—			135,517
Assets from risk management activities (Note 7)		15,420			17,169
Deferred fuel and purchased power regulatory asset (Note 3)		1,043			20,755
Other regulatory assets (Note 3)		77,148			76,388
Other current assets		48,457			39,895
Total current assets		999,072			1,043,609
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 7)		21,581			23,815
Nuclear decommissioning trust (Note 13)		682,359			642,007
Other assets		61,380			60,875
Total investments and other assets		765,320			726,697
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		15,448,087			15,200,464
Accumulated depreciation and amortization		(5,388,667		)	(5,300,219		)
Net		10,059,420			9,900,245
Construction work in progress		584,152			581,369
Palo Verde sale leaseback, net of accumulated depreciation (Note 6)		123,190			125,125
Intangible assets, net of accumulated amortization		137,037			157,689
Nuclear fuel, net of accumulated amortization		125,246			124,557
Total property, plant and equipment		11,029,045			10,888,985
DEFERRED DEBITS
Regulatory assets (Note 3)		755,174			711,712
Other		141,706			137,683
Total deferred debits		896,880			849,395
TOTAL ASSETS		$	13,690,317		$	13,508,686

 

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited)

(dollars in thousands)

 

		June 30, 2014			December 31, 2013
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable		$	320,779		$	284,516
Accrued taxes (Note 5)		161,707			130,998
Accrued interest		52,740			48,351
Common dividends payable		62,656			62,528
Short-term borrowings (Note 2)		176,650			153,125
Current maturities of long-term debt (Note 2)		368,841			540,424
Customer deposits		74,779			76,101
Liabilities from risk management activities (Note 7)		21,502			31,892
Liabilities for asset retirements		35,726			32,896
Regulatory liabilities (Note 3)		114,204			99,273
Other current liabilities		165,123			158,540
Total current liabilities		1,554,707			1,618,644
LONG-TERM DEBT LESS CURRENT MATURITIES (Note 2)		2,999,513			2,796,465
DEFERRED CREDITS AND OTHER
Deferred income taxes		2,396,026			2,351,882
Regulatory liabilities (Note 3)		809,442			801,297
Liabilities for asset retirements (Note 16)		356,436			313,833
Liabilities for pension and other postretirement benefits (Note 4)		439,490			513,628
Liabilities from risk management activities (Note 7)		23,367			70,315
Customer advances		120,330			114,480
Coal mine reclamation		208,951			207,453
Deferred investment tax credit		181,236			152,361
Unrecognized tax benefits (Note 5)		22,814			42,209
Other		196,143			185,659
Total deferred credits and other		4,754,235			4,753,117
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 8)
Common stock, no par value; authorized 150,000,000 shares, 110,430,456 and 110,280,703 issued at respective dates		2,500,064			2,491,558
Treasury stock at cost; 23,824 and 98,944 shares at respective dates		(189		)	(4,308		)
Total common stock		2,499,875			2,487,250
Retained earnings		1,808,232			1,785,273
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(55,848		)	(54,995		)
Derivative instruments		(18,369		)	(23,058		)
Total accumulated other comprehensive loss		(74,217		)	(78,053		)
Total shareholders’ equity		4,233,890			4,194,470
Noncontrolling interests (Note 6)		147,972			145,990
Total equity		4,381,862			4,340,460
TOTAL LIABILITIES AND EQUITY		$	13,690,317		$	13,508,686

 

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

(dollars in thousands)

 

		Six Months Ended June 30,
		2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income		$	166,075		$	172,434
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		246,371			249,482
Deferred fuel and purchased power		1,315			36,183
Deferred fuel and purchased power amortization		18,399			10,921
Allowance for equity funds used during construction		(14,941		)	(13,129		)
Deferred income taxes		32,611			68,526
Deferred investment tax credit		28,875			20,159
Change in derivative instruments fair value		49			349
Changes in current assets and liabilities:
Customer and other receivables		(64,986		)	(79,408		)
Accrued unbilled revenues		(75,648		)	(68,763		)
Materials, supplies and fossil fuel		(9,435		)	(4,002		)
Income tax receivable		135,517			779
Other current assets		(14,038		)	(14,439		)
Accounts payable		30,725			85,563
Accrued taxes		30,709			4,253
Other current liabilities		19,978			(26,098		)
Change in margin and collateral accounts — assets		(2,107		)	(1,111		)
Change in margin and collateral accounts — liabilities		(22,425		)	14,600
Change in other long-term assets		(19,243		)	(23,796		)
Change in other long-term liabilities		(22,735		)	21,753
Net cash flow provided by operating activities		465,066			454,256
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(388,752		)	(376,601		)
Contributions in aid of construction		12,646			21,236
Allowance for borrowed funds used during construction		(7,560		)	(7,626		)
Proceeds from nuclear decommissioning trust sales		199,224			253,996
Investment in nuclear decommissioning trust		(207,848		)	(262,621		)
Other		(678		)	(262		)
Net cash flow used for investing activities		(392,968		)	(371,878		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		535,975			136,307
Repayment of long-term debt		(503,583		)	(40,127		)
Short-term borrowings and payments — net		23,525			(62,075		)
Dividends paid on common stock		(125,138		)	(116,231		)
Common stock equity issuance		12,625			9,751
Distributions to noncontrolling interests		(15,869		)	(9,197		)
Other		2			795
Net cash flow used for financing activities		(72,463		)	(80,777		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(365		)	1,601
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		9,526			26,202
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	9,161		$	27,803

 

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.

 

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

1.                                       Consolidation and Nature of Operations

 

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries:  APS and El Dorado Investment Company (“El Dorado”).  Intercompany accounts and transactions between the consolidated companies have been eliminated.  The unaudited condensed consolidated financial statements for APS include the accounts of APS and the Palo Verde Nuclear Generating Station (“Palo Verde”) sale leaseback variable interest entities (“VIEs”) (see Note 6 for further discussion).  Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (“GAAP”).  The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period.  Actual results could differ from those estimates.

 

Weather conditions cause significant seasonal fluctuations in our revenues; therefore, results for interim periods do not necessarily represent results expected for the year.

 

Our condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (“SEC”).  Certain information and footnote disclosures normally included in financial statements prepared in conformity with GAAP have been condensed or omitted pursuant to such regulations, although we believe that the disclosures provided are adequate to make the interim information presented not misleading.

 

The following table shows more detail of previously reported amounts for the changes in accrued taxes and income tax receivable.  Previously reported amounts were netted in the Statement of Cash Flows (dollars in thousands):

 

Statement of Cash Flows for the Six Months Ended June 30, 2013		As previously reported			Changes to conform to current year presentation			Amount reported after changes to conform to current year presentation
Cash Flows from Operating Activities
Accrued taxes and income tax receivable		$	5,032		$	(5,032	)	$	—
Income tax receivable - net		—			779			779
Accrued taxes		—			4,253			4,253

 

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Supplemental Cash Flow Information

 

The following table summarizes supplemental Pinnacle West cash flow information (dollars in thousands):

 

		Six Months Ended June 30,
		2014			2013
Cash paid (received) during the period for:
Income taxes, net of refunds		$	(131,154	)	$	(9	)
Interest, net of amounts capitalized		90,707			91,346
Significant non-cash investing and financing activities:
Accrued capital expenditures		$	19,668		$	8,904
Dividends accrued but not yet paid		62,656			59,946

 

2.                                       Long-Term Debt and Liquidity Matters

 

Pinnacle West and APS maintain committed revolving credit facilities in order to enhance liquidity and provide credit support for their commercial paper programs.

 

Pinnacle West

 

On May 9, 2014, Pinnacle West replaced its $200 million revolving credit facility that would have matured in November 2016, with a new $200 million facility that matures in May 2019.  At June 30, 2014, the facility was available to refinance indebtedness of the Company and for other general corporate purposes, including credit support for its $200 million commercial paper program.  Pinnacle West has the option to increase the amount of the facility up to a maximum of $300 million upon the satisfaction of certain conditions and with the consent of the lenders.  At June 30, 2014, Pinnacle West had commercial paper borrowings of $4 million, no outstanding borrowings under its credit facility and no letters of credit outstanding.

 

APS

 

On July 12, 2013, APS purchased all $33 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 1994 Series A, due 2029.  On October 11, 2013, APS purchased all $32 million of the City of Farmington, New Mexico Pollution Control Revenue Bonds, 1994 Series C, due 2024.  On January 15, 2014, both of these series of bonds were canceled and refinanced as described below.

 

On January 10, 2014, APS issued $250 million of 4.70% unsecured senior notes that mature on January 15, 2044.  The proceeds from the sale were used to repay commercial paper which was used to fund the acquisition of Southern California Edison’s (“SCE”) 48% ownership interest in each of Units 4 and 5 of the Four Corners Power Plant (“Four Corners”) and to replenish cash used in 2013 to re-acquire the two series of tax-exempt indebtedness listed above.

 

On May 1, 2014, APS purchased a total of $100 million of the Maricopa County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, D and E, due 2029 in connection with the mandatory tender provisions for this indebtedness.  On May 14, 2014, APS remarketed all $36 million of the 2009 Series A Bonds, which are classified as long-term debt on our

 

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Condensed Consolidated Balance Sheets at June 30, 2014.  We expect to remarket or refinance all $64 million of the 2009 Series D Bonds and 2009 Series E Bonds within the next twelve months, which were classified as current maturities of long-term debt at December 31, 2013.

 

On May 9, 2014, APS replaced its $500 million revolving credit facility that would have matured in November 2016, with a new $500 million facility that matures in May 2019.

 

On May 30, 2014, APS purchased all $38 million of the Navajo County, Arizona, Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034, and on June 1, 2014, APS purchased a total of $64 million of the Navajo 2009 Series B Bonds and 2009 Series C Bonds, in each case, in connection with the mandatory tender provisions for this indebtedness.  We expect to remarket or refinance these bonds within the next twelve months.  These bonds were classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at December 31, 2013.

 

On June 1, 2014, APS remarketed all $13 million of the Coconino County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series A, due 2034.  These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets at June 30, 2014.

 

On June 18, 2014, APS issued $250 million of 3.35% unsecured senior notes that mature on June 15, 2024.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $300 million aggregate principal amount of 5.80% senior notes due June 30, 2014.

 

At June 30, 2014, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in April 2018 and the $500 million facility that matures in May 2019 (see above).  APS may increase the amount of each facility up to a maximum of $700 million upon the satisfaction of certain conditions and with the consent of the lenders.  APS will use these facilities to refinance indebtedness and for other general corporate purposes.  Interest rates are based on APS’s senior unsecured debt credit ratings.

 

The facilities described above are available to support APS’s $250 million commercial paper program, for bank borrowings or for issuances of letters of credit.  At June 30, 2014, APS had $173 million of commercial paper borrowings and no outstanding borrowings or outstanding letters of credit under these credit facilities.

 

See “Financial Assurances” in Note 9 for a discussion of APS’s separate outstanding letters of credit.

 

Debt Fair Value

 

Our long-term debt fair value estimates are based on quoted market prices for the same or similar issues, and are classified within Level 2 of the fair value hierarchy.  Certain of our debt instruments contain third-party credit enhancements and, in accordance with GAAP, we do not consider the effect of these credit enhancements when determining fair value.  The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 

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		As of June 30, 2014						As of December 31, 2013
		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Pinnacle West		$	125		$	125		$	125		$	125
APS		3,243			3,628			3,212			3,454
Total		$	3,368		$	3,753		$	3,337		$	3,579

 

Debt Provisions

 

An existing ACC order requires APS to maintain a common equity ratio of at least 40%.  As defined in the ACC order, the common equity ratio is total shareholder equity divided by the sum of total shareholder equity and long-term debt, including current maturities of long-term debt.  At June 30, 2014, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $4.3 billion, and total capitalization was approximately $7.5 billion.  APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $3.0 billion, assuming APS’s total capitalization remains the same.

 

3.                                       Regulatory Matters

 

Retail Rate Case Filing with the Arizona Corporation Commission

 

On June 1, 2011, APS filed an application with the ACC for a net retail base rate increase of $95.5 million.  APS requested that the increase become effective July 1, 2012.  The request would have increased the average retail customer bill by approximately 6.6%.  On January 6, 2012, APS and other parties to the general retail rate case entered into an agreement (the “2012 Settlement Agreement”) detailing the terms upon which the parties agreed to settle the rate case.  On May 15, 2012, the ACC approved the 2012 Settlement Agreement without material modifications.

 

Settlement Agreement

 

The 2012 Settlement Agreement provides for a zero net change in base rates, consisting of:  (1) a non-fuel base rate increase of $116.3 million; (2) a fuel-related base rate decrease of $153.1 million (to be implemented by a change in the base fuel rate for fuel and purchased power costs (“Base Fuel Rate”) from $0.03757 to $0.03207 per kilowatt hour (“kWh”); and (3) the transfer of cost recovery for certain renewable energy projects from the Arizona Renewable Energy Standard and Tariff (“RES”) surcharge to base rates in an estimated amount of $36.8 million.

 

APS also agreed not to file its next general rate case before May 31, 2015, and not to request that its next general retail rate increase be effective prior to July 1, 2016.  The 2012 Settlement Agreement allows APS to request a change to its base rates during the stay-out period in the event of an extraordinary event that, in the ACC’s judgment, requires base rate relief in order to protect the public interest.  Nor is APS precluded from seeking rate relief, or any other party to the 2012 Settlement Agreement precluded from petitioning the ACC to examine the reasonableness of APS’s rates, in the event of significant regulatory developments that materially impact the financial results expected under the terms of the 2012 Settlement Agreement.

 

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Other key provisions of the 2012 Settlement Agreement include the following:

 

·                                           An authorized return on common equity of 10.0%;

 

·                                           A capital structure comprised of 46.1% debt and 53.9% common equity;

 

·                                           A test year ended December 31, 2010, adjusted to include plant that is in service as of March 31, 2012;

 

·                                           Deferral for future recovery or refund of property taxes above or below a specified 2010 test year level caused by changes to the Arizona property tax rate as follows:

 

·                                           Deferral of increases in property taxes of 25% in 2012, 50% in 2013 and 75% for 2014 and subsequent years if Arizona property tax rates increase; and

 

·                                           Deferral of 100% in all years if Arizona property tax rates decrease;

 

·                                           A procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners (APS made its filing under this provision on December 30, 2013, which would result in an average bill impact to residential customers of approximately 2% if approved as requested);

 

·                                           Implementation of a Lost Fixed Cost Recovery (“LFCR”) rate mechanism to support energy efficiency and distributed renewable generation;

 

·                                           Modifications to the Environmental Improvement Surcharge (“EIS”) to allow for the recovery of carrying costs for capital expenditures associated with government-mandated environmental controls, subject to an existing cents per kWh cap on cost recovery that could produce up to approximately $5 million in revenues annually;

 

·                                           Modifications to the Power Supply Adjustor (“PSA”), including the elimination of the 90/10 sharing provision;

 

·                                           A limitation on the use of the RES surcharge and the Demand Side Management Adjustor Charge (“DSMAC”) to recoup capital expenditures not required under the terms of APS’s 2009 retail rate case settlement agreement (the “2009 Settlement Agreement”);

 

·                                           Allowing a negative credit that existed in the PSA rate to continue until February 2013, rather than being reset on the anticipated July 1, 2012 rate effective date;

 

·                                           Modification of the transmission cost adjustor (“TCA”) to streamline the process for future transmission-related rate changes; and

 

·                                           Implementation of various changes to rate schedules, including the adoption of an experimental “buy-through” rate that could allow certain large commercial and industrial customers to select alternative sources of generation to be supplied by APS.

 

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The 2012 Settlement Agreement was approved by the ACC on May 15, 2012, with new rates effective on July 1, 2012.  This accomplished a goal set by the parties to the 2009 Settlement Agreement to process subsequent rate cases within twelve months of sufficiency findings from the ACC staff, which generally occurs within 30 days after the filing of a rate case.

 

Cost Recovery Mechanisms

 

APS has received regulatory decisions that allow for more timely recovery of certain costs through the following recovery mechanisms.

 

Renewable Energy Standard .   In 2006, the ACC approved the RES.  Under the RES, electric utilities that are regulated by the ACC must supply an increasing percentage of their retail electric energy sales from eligible renewable resources, including solar, wind, biomass, biogas and geothermal technologies.  In order to achieve these requirements, the ACC allows APS to include a RES surcharge as part of customer bills to recover the approved amounts for use on renewable energy projects.  Each year APS is required to file a five-year implementation plan with the ACC and seek approval for funding the upcoming year’s RES budget.

 

On July 12, 2013, APS filed its annual RES implementation plan, covering the 2014-2018 timeframe and requesting a 2014 RES budget of approximately $143 million.  In a final order dated January 7, 2014, the ACC approved the requested budget.  Also in 2013, the ACC conducted a hearing to consider APS’s proposal to establish compliance with distributed energy requirements by tracking and recording distributed energy, rather than acquiring and retiring renewable energy credits.  On February 6, 2014, the ACC established a proceeding to modify the renewable energy rules to establish a process for compliance with the renewable energy requirement that is not based solely on the use of renewable energy credits.  On April 4, 2014, ACC staff submitted a proposal outlining various options which could be used to determine compliance with the renewable energy rules.  APS filed comments on the proposal and is awaiting the ACC’s selection of a proposal and modification of the rules to implement such proposal.

 

In accordance with the ACC’s decision on the 2014 RES plan, on April 15, 2014, APS filed an application with the ACC requesting permission to build an additional 20 MW of APS-owned utility scale solar under the AZ Sun Program.  In a subsequent filing, APS also offered an alternative proposal to replace the 20 MW of utility scale solar with 20 MW of APS-owned residential solar.

 

On July 1, 2014, APS filed its 2015 RES implementation plan and proposed a RES budget of approximately $154 million.

 

Demand Side Management Adjustor Charge .   The ACC Electric Energy Efficiency Standards require APS to submit a Demand Side Management Implementation Plan (“DSM Plan”) for review by and approval of the ACC.

 

On June 1, 2012, APS filed its 2013 DSM Plan.  In 2013, the standards required APS to achieve cumulative energy savings equal to 5% of its 2012 retail energy sales.  Later in 2012, APS filed a supplement to its plan that included a proposed budget for 2013 of $87.6 million.

 

On March 11, 2014, the ACC issued an order approving APS’s 2013 DSM Plan.  The ACC approved a budget of $68.9 million for each of 2013 and 2014.  The ACC also approved a Resource Savings Initiative that allows APS to count towards compliance with the ACC Electric Energy Efficiency

 

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Standards, savings for improvements to APS’s transmission and delivery system, generation and facilities that have been approved through a DSM Plan.  Consistent with the ACC’s March 11, 2014 order, APS intends to continue its approved DSM programs in 2015.

 

On June 27, 2013, the ACC voted to open a new docket investigating whether the Electric Energy Efficiency Rules should be modified.  The ACC held a series of three workshops in March and April 2014 to investigate methodologies used to determine cost effective energy efficiency programs, cost recovery mechanisms, incentives, and potential changes to the Electric Energy Efficiency and Resource Planning Rules.

 

PSA Mechanism and Balance.  The PSA provides for the adjustment of retail rates to reflect variations in retail fuel and purchased power costs.  The following table shows the changes in the deferred fuel and purchased power regulatory asset for 2014 and 2013 (dollars in millions):

 

		Six Months Ended June 30,
		2014			2013
Beginning balance		$	21		$	73
Deferred fuel and purchased power costs — current period		(1		)	(36		)
Amounts charged to customers		(19		)	(10		)
Ending balance		$	1		$	27

 

The PSA rate for the PSA year beginning February 1, 2014 is $0.001557 per kWh, as compared to $0.001329 per kWh for the prior year.  This new rate is comprised of a forward component of $0.001277 per kWh and a historical component of $0.000280 per kWh.  Any uncollected (overcollected) deferrals during the 2014 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2015.

 

Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters .  In July 2008, the United States Federal Regulatory Commission (“FERC”) approved an Open Access Transmission Tariff for APS to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect and recover the costs that APS incurs in providing transmission services.  A large portion of the rate represents charges for transmission services to serve APS’s retail customers (“Retail Transmission Charges”).  In order to recover the Retail Transmission Charges, APS was previously required to file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  Under the terms of the 2012 Settlement Agreement (discussed above), however, an adjustment to rates to recover the Retail Transmission Charges will be made annually each June 1 and will go into effect automatically unless suspended by the ACC.

 

The formula rate is updated each year effective June 1 on the basis of APS’s actual cost of service, as disclosed in APS’s FERC Form 1 report for the previous fiscal year.  Items to be updated include actual capital expenditures made as compared with previous projections, transmission revenue credits and other items.  The resolution of proposed adjustments can result in significant volatility in the revenues to be collected.  APS reviews the proposed formula rate filing amounts with the ACC staff.  Any items or adjustments which are not agreed to by APS and the ACC staff can remain in dispute until settled or litigated at FERC.  Settlement or litigated resolution of disputed issues could require an extended period of time and could have a significant effect on the Retail Transmission Charge because

 

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any adjustment, though applied prospectively, may be calculated to account for previously over- or under-collected amounts.

 

Effective June 1, 2014, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $5.9 million for the twelve-month period beginning June 1, 2014 in accordance with the FERC-approved formula.  An adjustment to APS’s retail rates to recover FERC-approved transmission charges went into effect automatically on June 1, 2014.

 

Lost Fixed Cost Recovery Mechanism .   The LFCR mechanism permits APS to recover on an after-the-fact basis a portion of its fixed costs that would otherwise have been collected by APS in the kWh sales lost due to APS energy efficiency programs and to distributed generation such as rooftop solar arrays.  The fixed costs recoverable by the LFCR mechanism were established in the 2012 Settlement Agreement and amount to approximately 3.1 cents per residential kWh lost and 2.3 cents per non-residential kWh lost.  The LFCR adjustment has a year-over-year cap of 1% of retail revenues.  Any amounts left unrecovered in a particular year because of this cap can be carried over for recovery in a future year.  The kWh’s lost from energy efficiency are based on a third-party evaluation of APS’s energy efficiency programs.  Distributed generation sales losses are determined from the metered output from the distributed generation units or if metering is unavailable, through accepted estimating techniques.

 

APS filed its first LFCR adjustment on January 15, 2013 and will file for a LFCR adjustment every January thereafter.  On February 12, 2013, the ACC approved a LFCR adjustment of $5.1 million, representing a pro-rated amount for 2012 since the 2012 Settlement Agreement went into effect on July 1, 2012.  APS filed its 2014 annual LFCR adjustment on January 15, 2014, requesting a LFCR adjustment of $25.3 million, effective March 1, 2014.  The ACC approved APS’s LFCR adjustment without change on March 11, 2014, which became effective April 1, 2014.

 

Deregulation

 

On May 9, 2013, the ACC voted to re-examine the facilitation of a deregulated retail electric market in Arizona.  The ACC subsequently opened a docket for this matter and received comments from a number of interested parties on the considerations involved in establishing retail electric deregulation in the state.  One of these considerations is whether various aspects of a deregulated market, including setting utility rates on a “market” basis, would be consistent with the requirements of the Arizona Constitution.  On September 11, 2013, after receiving legal advice from the ACC staff, the ACC voted 4-1 to close the current docket and await full Constitutional authority before any further examination of this matter.  The motion approved by the ACC also included opening one or more new dockets in the future to explore options to offer more rate choices to customers and innovative changes within the existing cost-of-service regulatory model that could include elements of competition.  The ACC opened a new docket on November 4, 2013 to explore technological advances and innovative changes within the electric utility industry.  Workshops in this docket are being held in 2014.

 

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Net Metering

 

On July 12, 2013, APS filed an application with the ACC proposing a solution to fix the cost shift brought by the current net metering rules.  On December 3, 2013, the ACC issued its order on APS’s net metering proposal.  The ACC instituted a charge on customers who install rooftop solar panels after December 31, 2013, and directed APS to provide quarterly reports on the pace of rooftop solar adoption to assist the ACC in considering further increases.  The charge of $0.70 per kilowatt became effective on January 1, 2014, and is estimated to collect $4.90 per month from a typical future rooftop solar customer to help pay for their use of the electricity grid.  The new policy will be in effect until the next APS rate case.

 

In making its decision, the ACC determined that the current net metering program creates a cost shift, causing non-solar utility customers to pay higher rates to cover the costs of maintaining the electrical grid.  ACC staff and the state’s Residential Utility Consumer Office, among other organizations, also agreed that a cost shift exists.  The fixed charge does not increase APS’s revenue because it is credited to the LFCR, but it will modestly reduce the impact of the cost shift on non-solar customers.  The ACC acknowledged that the new charge addresses only a portion of the cost shift.  The ACC also required APS to file its next rate case in June 2015, the earliest date contemplated in the 2012 Settlement Agreement.

 

In May 2014, the ACC began conducting a series of workshops to, among other things, evaluate the role and value of the electric grid as it relates to rooftop solar and other issues regarding net metering.

 

On July 22, 2014, the ACC Commissioners voted to reopen the December 2013 net metering decision for the limited purpose of deciding whether to eliminate the requirement that APS file its next rate case in June 2015.  The vote included a request that parties comment in the docket about their thoughts on removing the filing date requirement and on the process for the broader discussion regarding rate design.  The Commissioners stated that they plan to vote at an August 2014 open  meeting on whether to eliminate the requirement that APS file a rate case in June 2015.

 

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Four Corners

 

On December 30, 2013, APS purchased SCE’s 48% ownership interest in each of Units 4 and 5 of Four Corners.  The 2012 Settlement Agreement includes a procedure to allow APS to request rate adjustments prior to its next general rate case related to APS’s acquisition of the additional interests in Units 4 and 5 and the related closure of Units 1-3 of Four Corners.  APS made its filing under this provision on December 30, 2013.  If approved, these adjustments would result in an average bill impact to residential customers of approximately 2%.  This includes the deferral for future recovery of all non-fuel operating costs for the acquired SCE interest in Four Corners, net of the non-fuel operating costs savings resulting from the closure of Units 1-3 from the date of closing of the purchase.  The 2012 Settlement Agreement also provides for deferral for future recovery of all unrecovered costs incurred in connection with the closure of Units 1-3.  The deferral balance related to the acquisition of SCE’s interest in Units 4 and 5 and the closure of Units 1-3 was $55 million as of June 30, 2014.  ACC staff and other intervenors have filed testimony in this matter with the ACC, and APS has filed rebuttal testimony.  Both ACC staff and the Residential Utility Customer Office have proposed adjustments to the return to be applied to the Four Corners investments until APS’s next rate case, which would result in a lower level of recovery than proposed by APS.  A hearing on this matter is scheduled to begin August 4, 2014, and we anticipate a decision by the end of 2014.  APS cannot predict the outcome of this matter.

 

As part of APS’s acquisition of SCE’s interest in Units 4 and 5, APS and SCE agreed, via a “Transmission Termination Agreement,” that upon closing of the acquisition, the companies would terminate an existing transmission agreement (“Transmission Agreement”) between the parties that provides transmission capacity on a system (the “Arizona Transmission System”) for SCE to transmit its portion of the output from Four Corners to California.  APS previously submitted a request to FERC related to this termination, which resulted in a FERC order denying rate recovery of $40 million that APS agreed to pay SCE associated with the termination.  APS and SCE negotiated an alternate arrangement under which SCE would assign its 1,555 MW capacity rights over the Arizona Transmission System to third-parties, including 300 MW to APS’s marketing and trading group.  However, this alternative arrangement was not approved by FERC.  In late March 2014, APS and SCE filed requests for rehearing with FERC.  We are unable to predict the timing or outcome of these requests.  Although APS and SCE continue to evaluate potential paths forward, it is possible that the terms of the Transmission Termination Agreement may again control.  As we previously disclosed, APS believes that the original denial by FERC of rate recovery under the Transmission Termination Agreement constitutes the failure of a condition that relieves APS of its obligations under that agreement.  If APS and SCE were unable to determine a resolution through negotiation, the Transmission Termination Agreement requires that disputes be resolved through arbitration.  APS is unable to predict the outcome of this matter if it proceeds to arbitration.  If the matter proceeds to arbitration and APS is not successful, APS may be required to record a charge to its results of operations.

 

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Regulatory Assets and Liabilities

 

The detail of regulatory assets is as follows (dollars in millions):

 

		Remaining Amortization		June 30, 2014						December 31, 2013
		Period		Current			Non-Current			Current			Non-Current
Pension and other postretirement benefits			(a)	$	—		$	342		$	—		$	314
Income taxes — allowance for funds used during construction (“AFUDC”) equity		2043		4			108			4			105
Deferred fuel and purchased power — mark-to-market (Note 7)		2016		—			17			5			29
Transmission vegetation management		2016		9			9			9			14
Coal reclamation		2038		8			14			8			18
Palo Verde VIEs (Note 6)		2046		—			43			—			41
Deferred compensation		2036		—			36			—			34
Deferred fuel and purchased power (b) (c)		2015		1			—			21			—
Tax expense of Medicare subsidy		2023		2			15			2			15
Loss on reacquired debt		2034		1			17			1			17
Income taxes — investment tax credit basis adjustment		2043		2			47			1			39
Pension and other postretirement benefits deferral		2015		8			—			8			4
Four Corners cost deferral		2024		—			55			—			37
Lost fixed cost recovery (b)		2015		34			—			25			—
Transmission cost adjustor (b)		2015		5			—			8			2
Retired power plant costs		2020		3			16			3			18
Deferred property taxes			(d)	—			24			—			11
Other		Various		1			12			2			14
Total regulatory assets (e)				$	78		$	755		$	97		$	712

 

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(a)                                  This asset represents the future recovery of pension and other postretirement benefit obligations through retail rates.  If these costs are disallowed by the ACC, this regulatory asset would be charged to Other Comprehensive Income (“OCI”) and result in lower future revenues.  See Note 4 for further discussion.

(b)                                  See “Cost Recovery Mechanisms” discussion above.

(c)                                   Subject to a carrying charge.

(d)                                  Per the provision of the 2012 Settlement Agreement.

 

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(e)                                   There are no regulatory assets for which the ACC has allowed recovery of costs, but not allowed a return by exclusion from rate base.  FERC rates are set using a formula rate as described in “Transmission Rates, Transmission Cost Adjustor and Other Transmission Matters.”

 

The detail of regulatory liabilities is as follows (dollars in millions):

 

		Remaining Amortization		June 30, 2014						December 31, 2013
		Period		Current			Non-Current			Current			Non-Current
Removal costs			(a)	$	29		$	293		$	28		$	303
Asset retirement obligations			(a)	—			274			—			266
Renewable energy standard (b)		2015		35			11			33			15
Income taxes — change in rates		2043		—			73			—			74
Spent nuclear fuel		2047		5			36			6			36
Deferred gains on utility property		2019		2			9			2			10
Income taxes — deferred investment tax credit		2043		3			94			3			79
Demand side management (b)		2015		35			—			27			—
Deferred fuel and purchased power — mark to market (Note 7)		2015		4			—			—			—
Other		Various		1			19			—			18
Total regulatory liabilities				$	114		$	809		$	99		$	801

 

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(a)                                  In accordance with regulatory accounting guidance, APS accrues for removal costs for its regulated assets, even if there is no legal obligation for removal.

(b)                                  See “Cost Recovery Mechanisms” discussion above.

 

4.                                       Retirement Plans and Other Benefits

 

Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a non-qualified supplemental excess benefit retirement plan, and other postretirement benefit plans for the employees of Pinnacle West and our subsidiaries.  Pinnacle West uses a December 31 measurement date for its pension and other postretirement benefit plans.  The market-related value of our plan assets is their fair value at the measurement date.

 

Certain pension and other postretirement benefit costs in excess of amounts recovered in electric retail rates were deferred in 2011 and 2012 as a regulatory asset for future recovery, pursuant to APS’s 2009 retail rate case settlement.  Pursuant to this order, we began amortizing the regulatory asset over three years beginning in July 2012.  We amortized approximately $2 million and $4 million for the three and six months ended June 30, 2014 and 2013, respectively.  The following table provides details of the plans’ net periodic benefit costs and the portion of these costs charged to expense (including administrative costs and excluding amounts capitalized as overhead construction, billed to electric plant participants or charged or amortized to the regulatory asset) (dollars in millions):

 

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