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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 March 31, 2012

 

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.

 

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).

 

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

 

ARIZONA PUBLIC SERVICE COMPANY

 

 

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

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 April 27, 2012: 109,477,427
ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of April 27, 2012: 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	39
	Item 2.	Management’s Discussion and Analysis of Financial Condition
		and Results of Operations	46
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	62
	Item 4.	Controls and Procedures	62
Part II			64
	Item 1.	Legal Proceedings	64
	Item 1A.	Risk Factors	64
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	64
	Item 5.	Other Information	65
	Item 6.	Exhibits	66
Signatures			69

 

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, 2011 (“2011 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 achieve timely and adequate rate recovery of our costs, including returns on debt and equity capital;

·                               our ability to manage capital expenditures and other 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;

·                               volatile fuel and purchased power costs;

·                               fuel and water supply availability;

·                               regulatory and judicial decisions, developments and proceedings;

·                               new legislation or regulation, including those relating to environmental requirements and nuclear plant operations;

·                               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;

·                               competition in retail and wholesale power markets;

·                              the duration and severity of the economic decline in Arizona and current real estate market conditions;

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

·                               changes to our credit ratings;

·                               the investment performance of the assets of our nuclear decommissioning trust, 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 Risk Factors described in Part I, Item 1A of our 2011 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 March 31,
		2012			2011
OPERATING REVENUES		$	620,631		$	648,847
OPERATING EXPENSES
Fuel and purchased power		216,309			212,007
Operations and maintenance		210,663			255,029
Depreciation and amortization		100,109			106,583
Taxes other than income taxes		42,475			37,624
Other expenses		3,068			1,820
Total		572,624			613,063
OPERATING INCOME		48,007			35,784
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction		4,756			5,395
Other income (Note 11)		760			1,690
Other expense (Note 11)		(4,068		)	(1,741		)
Total		1,448			5,344
INTEREST EXPENSE
Interest charges		56,967			61,077
Allowance for borrowed funds used during construction		(3,151		)	(3,576		)
Total		53,816			57,501
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(4,361		)	(16,373		)
INCOME TAXES		(4,645		)	(6,005		)
INCOME (LOSS) FROM CONTINUING OPERATIONS		284			(10,368		)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(505) and $330 (Note 13)		(765		)	694
NET LOSS		(481		)	(9,674		)
Less: Net income attributable to noncontrolling interests (Note 7)		7,776			5,461
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	(8,257	)	$	(15,135	)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		109,299			108,832
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		109,299			108,832
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Loss from continuing operations attributable to common shareholders — basic		$	(0.07	)	$	(0.15	)
Net loss attributable to common shareholders — basic		(0.08		)	(0.14		)
Loss from continuing operations attributable to common shareholders — diluted		(0.07		)	(0.15		)
Net loss attributable to common shareholders — diluted		(0.08		)	(0.14		)
DIVIDENDS DECLARED PER SHARE		$	0.525		$	0.525
AMOUNTS ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Loss from continuing operations, net of tax		$	(7,483	)	$	(15,838	)
Discontinued operations, net of tax		(774		)	703
Net loss attributable to common shareholders		$	(8,257	)	$	(15,135	)

 

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 March 31,
		2012			2011
NET LOSS		$	(481	)	$	(9,674	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAX
Derivative instruments:
Net unrealized gain (loss), net of tax benefit (expense) of $16,551 and $(390)		(25,352		)	598
Reclassification of net realized loss, net of tax benefit of $5,728 and $5,865		8,772			8,982
Pension and other postretirement benefits activity, net of tax expense of $631 and $566		966			866
Total other comprehensive income (loss)		(15,614		)	10,446
COMPREHENSIVE INCOME (LOSS)		(16,095		)	772
Less: Comprehensive income attributable to noncontrolling interests		7,776			5,461
COMPREHENSIVE LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS		$	(23,871	)	$	(4,689	)

 

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)

 

		March 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	20,710		$	33,583
Customer and other receivables		238,387			284,183
Accrued unbilled revenues		104,728			125,239
Allowance for doubtful accounts		(2,886		)	(3,748		)
Materials and supplies (at average cost)		213,290			204,387
Fossil fuel (at average cost)		26,850			22,000
Deferred income taxes		141,224			130,571
Income tax receivable (Note 6)		8,894			6,466
Assets from risk management activities (Note 8)		34,617			30,264
Deferred fuel and purchased power regulatory asset (Note 3)		5,310			27,549
Other regulatory assets (Note 3)		81,457			69,072
Other current assets		32,219			26,904
Total current assets		904,800			956,470
INVESTMENTS AND OTHER ASSETS
Assets from risk management activities (Note 8)		53,124			49,322
Nuclear decommissioning trust (Note 15)		541,989			513,733
Other assets		64,415			64,588
Total investments and other assets		659,528			627,643
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		13,928,709			13,753,971
Accumulated depreciation and amortization		(4,775,904		)	(4,709,991		)
Net		9,152,805			9,043,980
Construction work in progress		462,425			496,745
Palo Verde sale leaseback, net of accumulated depreciation (Note 7)		131,897			132,864
Intangible assets, net of accumulated amortization		170,198			170,571
Nuclear fuel, net of accumulated amortization		141,882			118,098
Total property, plant and equipment		10,059,207			9,962,258
DEFERRED DEBITS
Regulatory assets (Note 3)		1,344,523			1,352,079
Income tax receivable (Note 6)		69,069			68,633
Other		146,787			143,935
Total deferred debits		1,560,379			1,564,647
TOTAL ASSETS		$	13,183,914		$	13,111,018

 

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)

 

		March 31, 2012			December 31, 2011
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable		$	265,975		$	326,987
Accrued taxes (Note 6)		160,136			120,289
Accrued interest		44,736			54,872
Short-term borrowings		216,600			—
Current maturities of long-term debt		101,708			477,435
Customer deposits		74,297			72,176
Liabilities from risk management activities (Note 8)		89,207			53,968
Regulatory liabilities (Note 3)		89,622			88,362
Other current liabilities		115,618			148,616
Total current liabilities		1,157,899			1,342,705
LONG-TERM DEBT LESS CURRENT MATURITIES
Long-term debt less current maturities		3,275,651			2,953,507
Palo Verde sale leaseback lessor notes less current maturities (Note 7)		65,547			65,547
Total long-term debt less current maturities		3,341,198			3,019,054
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,918,995			1,925,388
Regulatory liabilities (Note 3)		754,210			737,332
Liability for asset retirements		284,839			279,643
Liabilities for pension and other postretirement benefits (Note 4)		1,277,227			1,268,910
Liabilities from risk management activities (Note 8)		64,168			82,495
Customer advances		113,514			116,805
Coal mine reclamation		118,113			117,896
Unrecognized tax benefits (Note 6)		72,622			72,270
Other		219,700			217,934
Total deferred credits and other		4,823,388			4,818,673
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
EQUITY (Note 9)
Common stock, no par value		2,450,296			2,444,247
Treasury stock		(6,471		)	(4,717		)
Total common stock		2,443,825			2,439,530
Retained earnings		1,468,869			1,534,483
Accumulated other comprehensive loss:
Pension and other postretirement benefits		(64,481		)	(65,447		)
Derivative instruments		(103,296		)	(86,716		)
Total accumulated other comprehensive loss		(167,777		)	(152,163		)
Total shareholders’ equity		3,744,917			3,821,850
Noncontrolling interests (Note 7)		116,512			108,736
Total equity		3,861,429			3,930,586
TOTAL LIABILITIES AND EQUITY		$	13,183,914		$	13,111,018

 

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)

 

		Three Months Ended March 31,
		2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss		$	(481	)	$	(9,674	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		118,487			123,298
Deferred fuel and purchased power		46,754			49,947
Deferred fuel and purchased power amortization		(24,514		)	(31,238		)
Allowance for equity funds used during construction		(4,756		)	(5,395		)
Deferred income taxes		(1,989		)	(41,005		)
Change in mark-to-market valuations		1,985			(284		)
Changes in current assets and liabilities:
Customer and other receivables		52,264			75,528
Accrued unbilled revenues		20,511			9,633
Materials, supplies and fossil fuel		(13,753		)	21,421
Other current assets		(3,502		)	(636		)
Accounts payable		(39,355		)	(24,543		)
Accrued taxes and income tax receivable — net		37,398			52,944
Other current liabilities		(39,804		)	(37,406		)
Change in unrecognized tax benefits		—			18,959
Change in margin and collateral accounts — assets		(1,853		)	4,220
Change in margin and collateral accounts — liabilities		(32,950		)	35,478
Change in other long-term assets		(21,469		)	(33,169		)
Change in other long-term liabilities		22,362			35,418
Net cash flow provided by operating activities		115,335			243,496
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(240,973		)	(191,553		)
Contributions in aid of construction		13,871			9,136
Allowance for borrowed funds used during construction		(3,151		)	(3,576		)
Proceeds from nuclear decommissioning trust sales		92,047			189,318
Investment in nuclear decommissioning trust		(96,360		)	(194,241		)
Other		(533		)	(1,879		)
Net cash flow used for investing activities		(235,099		)	(192,795		)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		319,081			175,000
Repayment of long-term debt		(375,727		)	(175,170		)
Short-term borrowings and payments — net		216,600			700
Dividends paid on common stock		(55,595		)	(55,300		)
Common stock equity issuance		4,289			11,727
Other		(1,757		)	(3,653		)
Net cash flow provided by (used for) financing activities		106,891			(46,696		)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(12,873		)	4,005
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		33,583			110,188
CASH AND CASH EQUIVALENTS AT END OF PERIOD		$	20,710		$	114,193
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of (refunds)		$	(650	)	$	—
Interest, net of amounts capitalized		$	62,892		$	55,997

 

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, SunCor Development Company (“SunCor”), El Dorado Investment Company (“El Dorado”) and formerly APS Energy Services Company, Inc. (“APSES”).  See Note 13 for discussion of the bankruptcy filing of SunCor and the sale of APSES.  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 7 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 reflect all adjustments (consisting only of normal recurring adjustments except as otherwise disclosed in the notes) that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented.  These condensed consolidated financial statements and notes have been prepared consistently with the 2011 Form 10-K with the exception of the reclassification of certain prior year amounts on our Condensed Consolidated Statements of Income in accordance with accounting requirements for reporting discontinued operations (see Note 13) and to conform to current year presentation, and on our Condensed Consolidated Statements of Cash Flows to conform to the current year presentation.

 

See Note 16 for discussion of amended guidance on the presentation of comprehensive income.

 

The following tables show the impact of the reclassifications to prior year (previously reported) amounts (dollars in thousands):

 

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

Statement of Income for the Three Months Ended March 31, 2011		As previously reported			Reclassifications for discontinued operations and to conform to current year presentation			Amount reported after reclassification for discontinued operations and to conform to current year presentation
Operating Revenues
Regulated electricity segment revenues		$	647,974		$	(647,974	)	$	—
Other revenues		11,601			(11,601		)	—
Operating revenues		—			648,847			648,847
Operating Expenses
Operations and maintenance		256,486			(1,457		)	255,029
Depreciation and amortization		106,601			(18		)	106,583
Other expenses		9,716			(7,896		)	1,820
Other
Other expense		(1,699		)	(42		)	(1,741		)
Income Taxes		(5,649		)	(356		)	(6,005		)
Income From Continuing Operations		(9,325		)	(1,043		)	(10,368		)
Income From Discontinued Operations		(349		)	1,043			694

 

Statement of Cash Flows for the Three Months Ended March 31, 2011		As previously reported			Reclassifications to conform to current year presentation			Amount reported after reclassification to conform to current year presentation
Cash Flows from Operating Activities
Expenditures for real estate investments		$	(40	)	$	40		$	—
Gains and other changes in real estate assets		(3		)	3			—
Change in other long-term assets		(33,129		)	(40		)	(33,169		)
Change in other long-term liabilities		35,421			(3		)	35,418

 

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

 

At March 31, 2012, Pinnacle West’s $200 million credit facility, which matures in November 2016, 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 March 31, 2012, Pinnacle West had no

 

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

outstanding borrowings under its credit facility, no letters of credit outstanding and no commercial paper borrowings.

 

APS

 

On January 13, 2012, APS issued $325 million of 4.50% unsecured senior notes that mature on April 1, 2042.  The net proceeds from the sale were used along with other funds to repay at maturity APS’s $375 million aggregate principal amount of 6.50% senior notes on March 1, 2012.

 

At March 31, 2012, APS had two credit facilities totaling $1 billion, including a $500 million credit facility that matures in February 2015, and a $500 million facility that matures in November 2016.  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 March 31, 2012, APS had commercial paper borrowings of $217 million, and no borrowings or letters of credit outstanding under either of these credit facilities.

 

On May 1, 2012, APS purchased all $32 million of the Maricopa County, Arizona Pollution Control Corporation Pollution Control Revenue Refunding Bonds, 2009 Series B, due 2029.  We expect to remarket these bonds within the next twelve months.  These bonds are classified as current maturities of long-term debt on our Condensed Consolidated Balance Sheets at March 31, 2012 and December 31, 2011.

 

See “Financial Assurances” in Note 10 for discussion of APS’s outstanding letters of credit.

 

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PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

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. See Note 14 for discussion of the fair value hierarchy. The following table represents the estimated fair value of our long-term debt, including current maturities (dollars in millions):

 

		As of March 31, 2012						As of December 31, 2011
		Carrying Amount			Fair Value			Carrying Amount			Fair Value
Pinnacle West		$	125		$	123		$	125		$	123
APS		3,318			3,748			3,371			3,803
Total		$	3,443		$	3,871		$	3,496		$	3,926

 

Debt Provisions

 

An 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 March 31, 2012, APS was in compliance with this common equity ratio requirement.  Its total shareholder equity was approximately $3.9 billion, and total capitalization was approximately $7.1 billion. APS would be prohibited from paying dividends if the payment would reduce its total shareholder equity below approximately $2.8 billion, assuming APS’s total capitalization remains the same.  Since APS was in compliance with this common equity ratio requirement, this restriction does not materially affect Pinnacle West’s ability to meet its ongoing cash needs.

 

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 increase the average retail customer bill approximately 6.6%.  The filing is based on a test year ended December 31, 2010, adjusted as described below.  On January 6, 2012, APS and other parties to APS’s pending general retail rate case entered into an agreement (the “Settlement Agreement”) detailing the terms upon which the parties have agreed to settle the rate case.  The Settlement Agreement requires the approval of the ACC.  Evidentiary hearings on the matter were completed on February 3, 2012 and briefs from the parties were filed on February 29, 2012.  See below for details regarding the Settlement Agreement.

 

The key financial provisions of APS’s original request included:

 

·                                           An increase in non-fuel base rates of $194.1 million, before the reclassification into base rates of $44.9 million of revenues related to solar generation projects collected through APS’s renewable energy surcharge (which will increase base rates) and $143.5

 

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million of lower fuel and purchased power costs currently addressed through the Power Supply Adjustor (“PSA”) (which will decrease base rates);

 

·                                           A rate base of $5.7 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2010, subject to certain adjustments, including plant additions under construction at the end of the test year that are currently in service or expected to be placed into service before the proposed rates are requested to become effective;

 

·                                           The following proposed capital structure and costs of capital:

 

		Capital Structure		Cost of Capital
Long-term debt		46.1	%	6.38	%
Common stock equity		53.9	%	11.00	%
Weighted-average cost of capital				8.87	%

 

·                                           A base rate for fuel and purchased power costs (“Base Fuel Rate”) of $0.03242 per kilowatt-hour (“kWh”) based on estimated 2012 prices (a decrease from the current Base Fuel Rate of $0.03757 per kWh).

 

APS proposed that its PSA be modified to allow full pass-through of all fuel and purchased power costs, instead of the current 90/10 sharing provision.  In addition, APS proposed a decoupling mechanism, which would address recovery of APS’s fixed costs after reflecting implementation of ACC-mandated energy efficiency standards and renewable distributed generation.

 

Settlement Agreement

 

The 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 from $0.03757 to $0.03207 per 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 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 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 Settlement Agreement.

 

Other key provisions of the 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;

 

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·                                           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 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 proposed acquisition (should it be consummated) of additional interests in Units 4 and 5 and the related closure of Units 1-3 of the Four Corners Power Plant (“Four Corners”);

 

·                                           Implementation of a “Lost Fixed Cost Recovery” 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 approximately $5 million annually;

 

·                                           Modifications to the PSA, including the elimination of the current 90/10 sharing provision;

 

·                                           Allowing a negative credit that currently exists in the PSA 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.

 

If the Settlement Agreement is approved by the ACC, APS expects that its provisions will become effective on or about July 1, 2012.  As is the case with all such agreements, APS cannot predict whether the Settlement Agreement will be approved in the form filed or what changes may be ordered by the ACC and accepted by the parties.

 

2008 General Retail Rate Case Impacts

 

On December 30, 2009, the ACC issued an order approving a settlement agreement entered into by APS and twenty-one other parties in APS’s prior general retail rate case, which was originally filed in March 2008.  The settlement agreement included a net retail rate increase of $207.5 million, which represented a base rate increase of $344.7 million less a reclassification of $137.2 million of fuel

 

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and purchased power revenues from the then-existing PSA to base rates.  The new rates were effective January 1, 2010.  The settlement agreement also contained on-going requirements, commitments and authorizations, including the following:

 

·                                           Revenue accounting treatment for line extension payments received for new or upgraded service from January 1, 2010 through year end 2012 (or until new rates are established in APS’s next general rate case, if that is before the end of 2012);

 

·                                           An authorized return on common equity of 11%;

 

·                                           A capital structure comprised of 46.2% debt and 53.8% common equity;

 

·                                           A commitment from APS to reduce average annual operational expenses by at least $30 million from 2010 through 2014 (APS filed a notification with the ACC on April 29, 2011, demonstrating its compliance with this provision in 2010);

 

·                                           Authorization and requirements of equity infusions into APS of at least $700 million during the period beginning June 1, 2009 through December 31, 2014 ($253 million of which was infused into APS from proceeds of a Pinnacle West equity issuance in the second quarter of 2010); and

 

·                                           Various modifications to the existing energy efficiency, demand-side management and renewable energy programs that require APS to, among other things, expand its conservation and demand-side management programs and its use of renewable energy, as well as allow for concurrent recovery of renewable energy expenses and provide for more concurrent recovery of demand-side management costs and incentives.

 

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 1, 2011, APS filed its annual RES implementation plan, covering the 2012-2016  timeframe and requesting 2012 RES funding of $129 million to $152 million.  On December 14, 2011, the ACC voted to approve APS’s 2012 RES Plan and authorized a total 2012 RES budget of $110 million.  Within that budget, the ACC authorized APS to, among other items, (i) own an additional 100 megawatts (“MW”) under the AZ Sun Program, for a total of 200 MW; (ii) recover revenue requirements for the second 100 MW as APS did for the first 100 MW of the AZ Sun Program; (iii) expand APS’s School and Government Program by another 6.25 MW of utility owned distributed generation; and (iv) own another 25 MW of renewable generation to be described later and installed in

 

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2014 and 2015.  In addition, the ACC ordered an initial up front incentive of $0.75 per watt for residential distributed energy and incentive level step downs throughout 2012 based upon the volume and timing of residential incentive applications.  Under the ACC’s order, residential incentives could fall to $0.20 or $0.10 per watt by the end of 2012 depending on demand.

 

Demand-Side Management Adjustor Charge (“DSMAC”).   The settlement agreement resulting from the 2008 retail rate case requires APS to submit an annual Demand-Side Management Implementation Plan for review by and approval of the ACC.  In 2010, the DSMAC was modified to recover estimated amounts for use on certain demand-side management programs over the current year.  Previously, the DSMAC allowed for such recovery only on a historical or after-the-fact basis.  The surcharge allows for the recovery of energy efficiency program expenses and any earned incentives.

 

The ACC previously approved recovery of all 2009 program costs plus incentives.  The change from program cost recovery on a historical basis to recovery on a concurrent basis, as authorized in the 2008 retail rate case settlement agreement, resulted in this one-time need to address two years (2009 and 2010) of cost recovery.  As requested by APS, 2009 program cost recovery is to be amortized over a three-year period.

 

On June 1, 2010, APS filed its 2011 Demand-Side Management Implementation Plan. In order to meet the energy efficiency goal for 2011 established by the settlement agreement of annual energy savings of 1.25%, expressed as a percent of total energy resources to meet retail load, APS proposed a total budget for 2011 of $79 million.  On February 17, 2011, a total budget for 2011 of $80 million was approved and, when added to the amortization of 2009 program costs discussed in the previous paragraph less the $10 million already being recovered in general retail base rates, the DSMAC would recover approximately $75 million over a twelve-month period beginning March 1, 2011.

 

On June 1, 2011, APS filed its 2012 Demand-Side Management Implementation Plan to meet the energy efficiency requirements of the ACC’s Energy Efficiency Rules, which became effective January 1, 2011. The 2012 requirement under such rules is for energy efficiency savings of 1.75% of APS retail sales for the prior year. This energy savings requirement is slightly higher than the goal established by the 2008 retail rate case settlement agreement (1.5% of total energy resources). The ACC issued an order on April 4, 2012 approving recovery of approximately $72 million over a twelve-month period beginning March 1, 2012.  This amount does not include $10 million already being recovered in general retail base rates.

 

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 (liability) for 2012 and 2011 (dollars in millions):

 

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		Three Months Ended March 31,
		2012			2011
Beginning balance		$	28		$	(58	)
Deferred fuel and purchased power costs — current period		(47		)	(50		)
Amounts refunded through revenues		24			31
Ending balance		$	5		$	(77	)

 

The PSA rate for the PSA year beginning February 1, 2012 is negative $0.0042 per kWh as compared to negative $0.0057 per kWh for the prior year.  Any uncollected (overcollected) deferrals during the 2012 PSA year will be included in the calculation of the PSA rate for the PSA year beginning February 1, 2013.

 

Transmission Rates and Transmission Cost Adjustor .  In July 2008, the United States Federal Energy 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 must file an application with, and obtain approval from, the ACC to reflect changes in Retail Transmission Charges through the TCA.  If the Settlement Agreement (discussed above) is approved, 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 any adjustment, though applied prospectively, may be calculated to account for previously over-collected amounts.

 

Effective June 1, 2011, APS’s annual wholesale transmission rates for all users of its transmission system increased by approximately $44 million for the twelve-month period beginning June 1, 2011 in accordance with the FERC-approved formula as a result of higher costs and lower revenues reflected in the formula.  Approximately $38 million of this revenue increase relates to Retail Transmission Charges.  The ACC approved the related increase of APS’s TCA rate on June 21, 2011 and it became effective on July 1, 2011.

 

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Regulatory Assets and Liabilities

 

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

 

		March 31, 2012						December 31, 2011
		Current			Non-Current			Current			Non-Current
Pension and other postretirement benefits		$	—		$	1,007		$	—		$	1,023
Income taxes — allowance for funds used during construction (“AFUDC”) equity		3			81			3			81
Deferred fuel and purchased power — mark-to-market (Note 8)		58			34			43			34
Transmission vegetation management		9			30			9			32
Coal reclamation		2			34			2			35
Palo Verde VIEs (Note 7)		—			36			—			35
Deferred compensation		—			34			—			33
Deferred fuel and purchased power (a)		5			—			28			—
Tax expense of Medicare subsidy		2			19			2			18
Loss on reacquired debt		1			19			1			19
Income taxes — investment tax credit basis adjustment		—			15			—			15
Pension and other postretirement benefits deferral		—			21			—			12
Demand-side management (a)		5			—			7			1
Other		2			15			2			14
Total regulatory assets (b)		$	87		$	1,345		$	97		$	1,352

 

(a)                                  See Cost Recovery Mechanisms discussion above.

(b)                                  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 and Transmission Cost Adjustor.”

 

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

 

		March 31, 2012						December 31, 2011
		Current			Non-Current			Current			Non-Current
Removal costs (a)		$	24		$	344		$	22		$	349
Asset retirement obligations		—			249			—			225
Renewable energy standard (b)		50			—			54			—
Income taxes — change in rates		—			59			—			59
Spent nuclear fuel		7			41			5			44
Deferred gains on utility property		2			14			2			14
Income taxes- deferred investment tax credit		1			32			1			30
Other		6			15			4			16
Total regulatory liabilities		$	90		$	754		$	88		$	737

 

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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 are deferred as a regulatory asset for future recovery, pursuant to an ACC regulatory order.  We deferred pension and other postretirement benefit costs of approximately $9 million for the three months ended March 31, 2012 and $3 million for the three months ended March 31, 2011.  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 to the regulatory asset) (dollars in millions):

 

		Pension Benefits						Other Benefits
		Three Months Ended March 31,						Three Months Ended March 31,
		2012			2011			2012			2011
Service cost - benefits earned during the period		$	16		$	16		$	7		$	6
Interest cost on benefit obligation		30			31			12			12
Expected return on plan assets		(35		)	(33		)	(11		)	(10		)
Amortization of net actuarial loss		11			6			6			3
Net periodic benefit cost		$	22		$	20		$	14		$	11
Portion of cost charged to expense		$	6		$	8		$	3		$	4

 

Contributions

 

The required minimum contribution to our pension plan is approximately $65 million in 2012, approximately $160 million in 2013 and approximately $175 million in 2014.  The contributions to our other postretirement benefit plans for 2012, 2013 and 2014 are expected to be approximately $20 million each year.

 

5.                                       Business Segments

 

Pinnacle West’s reportable business segment is our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily retail and wholesale sales supplied to traditional cost-based rate regulation (“Native Load”) customers) and related activities and includes electricity generation, transmission and distribution.

 

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Financial data for the three months ended March 31, 2012 and 2011 and at March 31, 2012 and December 31, 2011 is provided as follows (dollars in millions):

 

		Three Months Ended March 31,
		2012			2011
Operating revenues:
Regulated electricity segment		$	620		$	648
All other (a)		1			1
Total		$	621		$	649
Net loss attributable to common shareholders:
Regulated electricity segment		$	(6	)	$	(15	)
All other (a)		(2		)	—
Total		$	(8	)	$	(15	)

 

		As of March 31, 2012			As of December 31, 2011
Assets:
Regulated electricity segment		$	13,142		$	13,068
All other (a)		42			43
Total		$	13,184		$	13,111

 

(a)                                  All other activities relate to APSES, SunCor, Pinnacle West and El Dorado.  See Note 13 for discussion of discontinued operations.

 

6.                                       Income Taxes

 

The $69 million income tax receivable on the Condensed Consolidated Balance Sheets primarily represents the anticipated refunds related to an APS tax accounting method change approved by the Internal Revenue Service (“IRS”) in the third quarter of 2009.  This amount is classified as long-term, as there remains uncertainty regarding the timing of this cash receipt. Further clarification of the timing is expected from the IRS within the next twelve months.

 

Net income associated with the Palo Verde Sale Leaseback Variable Interest Entities is not subject to tax (see Note 7).  As a result, there is no income tax expense recorded on the Condensed Consolidated Statements of Income.

 

It is reasonably possible that within the next twelve months the IRS will finalize the examination of tax returns for the years ended December 31, 2008 and 2009. At this time, a reasonable estimate of the range of possible change in the uncertain tax position cannot be made.  However, we do not expect the ultimate outcome of this examination to have a material adverse impact on our financial position or results of operations.

 

On February 17, 2011, Arizona enacted legislation (H.B. 2001) that included a four year phase-in of corporate income tax rate reductions beginning in 2014.  As a result of these tax rate reductions, Pinnacle West has revised the tax rate applicable to reversing temporary items in Arizona.  In accordance with accounting for regulated companies, the benefit of this rate reduction is substantially offset by a regulatory liability.

 

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