Table of Contents

 
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-Q
(Mark One)
 	 	 	
þ	 	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the quarterly period ended March 31, 2007
OR
 	 	 	
o	 	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
For the transition period from                      to                     
 	 	 	 	 	
 	 	Exact Name of Each Registrant as specified in	 	 	
Commission	 	its charter; State of Incorporation; Address;	 	IRS Employer	
File Number	 	and Telephone Number	 	Identification No.	
 	 	PINNACLE WEST CAPITAL CORPORATION	 	 	
1-8962	 	(an Arizona corporation)	 	86-0512431	
 	 	400 North Fifth Street, P.O. Box 53999	 	 	
 	 	Phoenix, Arizona 85072-3999	 	 	
 	 	(602) 250-1000	 	 	
 	 	 	 	 	
 	 	ARIZONA PUBLIC SERVICE COMPANY	 	 	
1-4473	 	(an Arizona corporation)	 	86-0011170	
 	 	400 North Fifth Street, P.O. Box 53999	 	 	
 	 	Phoenix, Arizona 85072-3999	 	 	
 	 	(602) 250-1000	 	 	
     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  þ	 	No  o	
ARIZONA PUBLIC SERVICE COMPANY	 	Yes  þ	 	No  o	
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act.
PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer  þ       Accelerated filer  o       Non-accelerated filer  o
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer  o       Accelerated filer  o       Non-accelerated filer  þ
     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  þ	
ARIZONA PUBLIC SERVICE COMPANY	 	Yes  o	 	No  þ	
     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 May 3, 2007: 100,237,583	
ARIZONA PUBLIC SERVICE COMPANY	 	Number of shares of common stock, $2.50 par value, outstanding as of May 3, 2007: 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.
          This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing 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 filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

   

 

TABLE OF CONTENTS
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Page	 	
Glossary	 	 	 	 	2	 	
Part I	 	 	 	 	4	 	
 	 	Item 1.	 	Financial Statements	 	 	4	 	
 	 	 	 	Pinnacle West Capital Corporation	 	 	4	 	
 	 	 	 	Arizona Public Service Company	 	 	32	 	
 	 	Item 2.	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	41	 	
 	 	Item 3.	 	Quantitative and Qualitative Disclosures About Market Risk	 	 	60	 	
 	 	Item 4.	 	Controls and Procedures	 	 	60	 	
Part II	 	 	 	 	61	 	
 	 	Item 1.	 	Legal Proceedings	 	 	61	 	
 	 	Item 1A.	 	Risk Factors	 	 	61	 	
 	 	Item 5.	 	Other Information	 	 	61	 	
 	 	Item 6.	 	Exhibits	 	 	63	 	
Signatures	 	 	 	 	65	 	
  EX-10.1	
  EX-10.2	
  EX-12.1	
  EX-12.2	
  EX-12.3	
  EX-31.1	
  EX-31.2	
  EX-31.3	
  EX-31.4	
  EX-32.1	
  EX-32.2	
  EX-99.1	
  EX-99.2	

Table of Contents

GLOSSARY
ACC – Arizona Corporation Commission
ADEQ – Arizona Department of Environmental Quality
ALJ – Administrative Law Judge
APS – Arizona Public Service Company, a subsidiary of the Company
APS Energy Services – APS Energy Services Company, Inc., a subsidiary of the Company
Clean Air Act – Clean Air Act, as amended
Company – Pinnacle West Capital Corporation
DOE – United States Department of Energy
EITF – FASB’s Emerging Issues Task Force
El Dorado – El Dorado Investment Company, a subsidiary of the Company
EPA – United States Environmental Protection Agency
ERMC – Energy Risk Management Committee
FASB – Financial Accounting Standards Board
FERC – United States Federal Energy Regulatory Commission
FIN – FASB Interpretation Number
Fitch – Fitch, Inc.
Four Corners – Four Corners Power Plant
GAAP – accounting principles generally accepted in the United States of America
IRS – United States Internal Revenue Service
kWh – kilowatt-hour, one thousand watts per hour
Moody’s – Moody’s Investors Service
MWh – megawatt-hour, one million watts per hour
Native Load – retail and wholesale sales supplied under traditional cost-based rate regulation
Note – a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this report
NRC – United States Nuclear Regulatory Commission
OCI – other comprehensive income
Off-System Sales – sales of electricity from generation owned or contracted by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts
Palo Verde – Palo Verde Nuclear Generating Station
Pinnacle West – Pinnacle West Capital Corporation, the Company
Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006
 2 

Table of Contents

Pinnacle West Marketing & Trading – Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company
PRP – potentially responsible parties under Superfund
PSA – power supply adjustor
Salt River Project – Salt River Project Agricultural Improvement and Power District
SEC – United States Securities and Exchange Commission
SFAS – Statement of Financial Accounting Standards
Silverhawk – Silverhawk Power Station
Standard & Poor’s – Standard & Poor’s Corporation
SunCor – SunCor Development Company, a subsidiary of the Company
Sundance Plant – 450-megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona
Superfund – Comprehensive Environmental Response, Compensation and Liability Act
2006 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2006
VIE – variable interest entity
 3 

Table of Contents
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,	 	
 	 	2007	 	 	2006	 	
OPERATING REVENUES	 	 	 	 	 	 	 	 	
Regulated electricity segment	 	$	536,051	 	 	$	466,126	 	
Real estate segment	 	 	77,250	 	 	 	107,854	 	
Marketing and trading	 	 	72,471	 	 	 	85,002	 	
Other revenues	 	 	9,363	 	 	 	11,224	 	
 	 	 	 	 	 	 	
Total	 	 	695,135	 	 	 	670,206	 	
 	 	 	 	 	 	 	
OPERATING EXPENSES	 	 	 	 	 	 	 	 	
Regulated electricity segment fuel and purchased power	 	 	203,353	 	 	 	157,395	 	
Real estate segment operations	 	 	61,443	 	 	 	71,330	 	
Marketing and trading fuel and purchased power	 	 	57,944	 	 	 	74,175	 	
Operations and maintenance	 	 	171,578	 	 	 	178,427	 	
Depreciation and amortization	 	 	89,621	 	 	 	87,621	 	
Taxes other than income taxes	 	 	34,719	 	 	 	35,573	 	
Other expenses	 	 	8,488	 	 	 	8,522	 	
 	 	 	 	 	 	 	
Total	 	 	627,146	 	 	 	613,043	 	
 	 	 	 	 	 	 	
OPERATING INCOME	 	 	67,989	 	 	 	57,163	 	
 	 	 	 	 	 	 	
OTHER	 	 	 	 	 	 	 	 	
Allowance for equity funds used during construction	 	 	4,444	 	 	 	3,801	 	
Other income (Note 14)	 	 	4,512	 	 	 	5,467	 	
Other expense (Note 14)	 	 	(6,353	)	 	 	(4,541	)	
 	 	 	 	 	 	 	
Total	 	 	2,603	 	 	 	4,727	 	
 	 	 	 	 	 	 	
INTEREST EXPENSE	 	 	 	 	 	 	 	 	
Interest charges	 	 	50,992	 	 	 	47,526	 	
Capitalized interest	 	 	(4,807	)	 	 	(4,024	)	
 	 	 	 	 	 	 	
Total	 	 	46,185	 	 	 	43,502	 	
 	 	 	 	 	 	 	
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	 	 	24,407	 	 	 	18,388	 	
INCOME TAXES	 	 	8,609	 	 	 	6,793	 	
 	 	 	 	 	 	 	
INCOME FROM CONTINUING OPERATIONS	 	 	15,798	 	 	 	11,595	 	
INCOME FROM DISCONTINUED OPERATIONS	 	 	 	 	 	 	 	 	
Net of income tax expense of $479 and $557 (Note 17)	 	 	732	 	 	 	860	 	
 	 	 	 	 	 	 	
NET INCOME	 	$	16,530	 	 	$	12,455	 	
 	 	 	 	 	 	 	
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC	 	 	100,045	 	 	 	99,115	 	
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED	 	 	100,622	 	 	 	99,449	 	
 	 	 	 	 	 	 	 	 	
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING	 	 	 	 	 	 	 	 	
Income from continuing operations – basic	 	$	0.16	 	 	$	0.12	 	
Net income – basic	 	 	0.17	 	 	 	0.13	 	
Income from continuing operations – diluted	 	 	0.16	 	 	 	0.12	 	
Net income – diluted	 	 	0.16	 	 	 	0.13	 	
DIVIDENDS DECLARED PER SHARE	 	$	0.525	 	 	$	1.00	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.
 4 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	March 31,	 	 	December 31,	 	
 	 	2007	 	 	2006	 	
ASSETS	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
CURRENT ASSETS	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	$	121,253	 	 	$	87,210	 	
Investment in debt securities	 	 	—	 	 	 	32,700	 	
Customer and other receivables	 	 	371,467	 	 	 	501,628	 	
Allowance for doubtful accounts	 	 	(5,165	)	 	 	(5,597	)	
Materials and supplies (at average cost)	 	 	137,357	 	 	 	125,802	 	
Fossil fuel (at average cost)	 	 	24,856	 	 	 	21,973	 	
Deferred income taxes	 	 	—	 	 	 	982	 	
Assets from risk management and trading activities (Note 10)	 	 	245,458	 	 	 	641,040	 	
Assets held for sale	 	 	16,714	 	 	 	—	 	
Other current assets	 	 	59,162	 	 	 	68,924	 	
 	 	 	 	 	 	 	
Total current assets	 	 	971,102	 	 	 	1,474,662	 	

INVESTMENTS AND OTHER ASSETS	 	 	 	 	 	 	 	 	
Real estate investments – net	 	 	533,176	 	 	 	526,008	 	
Assets from long-term risk management and trading activities (Note 10)	 	 	152,271	 	 	 	167,211	 	
Decommissioning trust accounts (Note 18)	 	 	349,470	 	 	 	343,771	 	
Other assets	 	 	110,938	 	 	 	111,388	 	
 	 	 	 	 	 	 	
Total investments and other assets	 	 	1,145,855	 	 	 	1,148,378	 	

PROPERTY, PLANT AND EQUIPMENT	 	 	 	 	 	 	 	 	
Plant in service and held for future use	 	 	11,257,974	 	 	 	11,154,919	 	
Less accumulated depreciation and amortization	 	 	3,852,033	 	 	 	3,797,475	 	
 	 	 	 	 	 	 	
Net	 	 	7,405,941	 	 	 	7,357,444	 	
Construction work in progress	 	 	420,598	 	 	 	368,284	 	
Intangible assets, net of accumulated amortization	 	 	90,251	 	 	 	96,100	 	
Nuclear fuel, net of accumulated amortization	 	 	69,539	 	 	 	60,100	 	
 	 	 	 	 	 	 	
Total property, plant and equipment	 	 	7,986,329	 	 	 	7,881,928	 	

DEFERRED DEBITS	 	 	 	 	 	 	 	 	
Deferred fuel and purchased power regulatory asset (Note 5)	 	 	117,795	 	 	 	160,268	 	
Other regulatory assets	 	 	625,480	 	 	 	686,016	 	
Other deferred debits (Note 8)	 	 	162,396	 	 	 	104,691	 	
 	 	 	 	 	 	 	
Total deferred debits	 	 	905,671	 	 	 	950,975	 	

TOTAL ASSETS	 	$	11,008,957	 	 	$	11,455,943	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.
 5 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	March 31,	 	 	December 31,	 	
 	 	2007	 	 	2006	 	
LIABILITIES AND COMMON STOCK EQUITY	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
CURRENT LIABILITIES	 	 	 	 	 	 	 	 	
Accounts payable	 	$	226,649	 	 	$	346,047	 	
Accrued taxes (Note 8)	 	 	317,250	 	 	 	263,935	 	
Accrued interest	 	 	43,003	 	 	 	48,746	 	
Short-term borrowings	 	 	71,050	 	 	 	35,750	 	
Current maturities of long-term debt	 	 	61,428	 	 	 	1,596	 	
Customer deposits	 	 	72,382	 	 	 	70,168	 	
Deferred income taxes	 	 	10,744	 	 	 	—	 	
Liabilities from risk management and trading activities (Note 10)	 	 	148,827	 	 	 	558,195	 	
Other current liabilities	 	 	139,552	 	 	 	134,123	 	
 	 	 	 	 	 	 	
Total current liabilities	 	 	1,090,885	 	 	 	1,458,560	 	

LONG-TERM DEBT LESS CURRENT MATURITIES	 	 	3,186,998	 	 	 	3,232,633	 	

DEFERRED CREDITS AND OTHER	 	 	 	 	 	 	 	 	
Deferred income taxes	 	 	1,232,825	 	 	 	1,225,798	 	
Regulatory liabilities	 	 	646,424	 	 	 	635,431	 	
Liability for asset retirements	 	 	270,264	 	 	 	268,389	 	
Liabilities for pension and other postretirement benefits (Note 6)	 	 	600,358	 	 	 	588,852	 	
Liabilities from long-term risk management and trading activities (Note 10)	 	 	108,048	 	 	 	171,170	 	
Unamortized gain – sale of utility plant	 	 	40,038	 	 	 	41,182	 	
Other	 	 	384,195	 	 	 	387,812	 	
 	 	 	 	 	 	 	
Total deferred credits and other	 	 	3,282,152	 	 	 	3,318,634	 	

COMMITMENTS AND CONTINGENCIES (NOTES 5, 8, 12, 13 and 15)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
COMMON STOCK EQUITY Common stock, no par value	 	 	2,121,070	 	 	 	2,114,550	 	
Treasury stock	 	 	(750	)	 	 	(449	)	
 	 	 	 	 	 	 	
Total common stock	 	 	2,120,320	 	 	 	2,114,101	 	
 	 	 	 	 	 	 	
Accumulated other comprehensive income (loss) (Note 11):	 	 	 	 	 	 	 	 	
Pension and other postretirement benefits	 	 	(19,110	)	 	 	(19,263	)	
Derivative instruments	 	 	66,606	 	 	 	31,531	 	
 	 	 	 	 	 	 	
Total accumulated other comprehensive income	 	 	47,496	 	 	 	12,268	 	
 	 	 	 	 	 	 	
Retained earnings	 	 	1,281,106	 	 	 	1,319,747	 	
 	 	 	 	 	 	 	
Total common stock equity	 	 	3,448,922	 	 	 	3,446,116	 	

TOTAL LIABILITIES AND COMMON STOCK EQUITY	 	$	11,008,957	 	 	$	11,455,943	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.
 6 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
CASH FLOWS FROM OPERATING ACTIVITIES	 	 	 	 	 	 	 	 	
Net Income	 	$	16,530	 	 	$	12,455	 	
Adjustments to reconcile net income to net cash provided by operating activities:	 	 	 	 	 	 	 	 	
Depreciation and amortization including nuclear fuel	 	 	98,719	 	 	 	95,072	 	
Deferred fuel and purchased power	 	 	(26,293	)	 	 	(14,538	)	
Deferred fuel and purchased power amortization	 	 	68,766	 	 	 	17,808	 	
Allowance for equity funds used during construction	 	 	(4,444	)	 	 	(3,801	)	
Deferred income taxes	 	 	(12,752	)	 	 	1,757	 	
Change in mark-to-market valuations	 	 	(5,494	)	 	 	9,305	 	
Changes in current assets and liabilities:	 	 	 	 	 	 	 	 	
Customer and other receivables	 	 	149,097	 	 	 	129,940	 	
Materials, supplies and fossil fuel	 	 	(14,438	)	 	 	4,186	 	
Other current assets	 	 	4,525	 	 	 	(7,537	)	
Accounts payable	 	 	(124,785	)	 	 	(124,577	)	
Collateral	 	 	(303	)	 	 	(170,690	)	
Other current liabilities	 	 	21,242	 	 	 	62,653	 	
Proceeds from the sale of real estate assets	 	 	16,824	 	 	 	7,884	 	
Real estate investments	 	 	(24,617	)	 	 	(28,670	)	
Change in risk management and trading – assets	 	 	54,689	 	 	 	67,984	 	
Change in risk management and trading – liabilities	 	 	(480	)	 	 	(66,096	)	
Change in other long-term assets	 	 	(11,900	)	 	 	(2,247	)	
Change in other long-term liabilities	 	 	9,695	 	 	 	12,169	 	
 	 	 	 	 	 	 	
Net cash flow provided by operating activities	 	 	214,581	 	 	 	3,057	 	

CASH FLOWS FROM INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(206,083	)	 	 	(167,367	)	
Capitalized interest	 	 	(4,807	)	 	 	(4,024	)	
Proceeds from the sale of Silverhawk	 	 	—	 	 	 	207,620	 	
Purchases of investment securities	 	 	(36,525	)	 	 	(269,526	)	
Proceeds from sale of investment securities	 	 	69,225	 	 	 	269,526	 	
Proceeds from nuclear decommissioning trust sales	 	 	63,490	 	 	 	33,743	 	
Investment in nuclear decommissioning trust	 	 	(68,675	)	 	 	(38,929	)	
Other	 	 	(626	)	 	 	654	 	
 	 	 	 	 	 	 	
Net cash flow provided by (used for) investing activities	 	 	(184,001	)	 	 	31,697	 	

CASH FLOWS FROM FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	
Issuance of long-term debt	 	 	53,257	 	 	 	206,848	 	
Repayment of long-term debt	 	 	(39,305	)	 	 	(39,587	)	
Short-term borrowings and payments – net	 	 	35,300	 	 	 	(70	)	
Dividends paid on common stock	 	 	(52,495	)	 	 	(49,608	)	
Common stock equity issuance	 	 	7,613	 	 	 	5,065	 	
Other	 	 	(907	)	 	 	3,450	 	
 	 	 	 	 	 	 	
Net cash flow provided by financing activities	 	 	3,463	 	 	 	126,098	 	

NET INCREASE IN CASH AND CASH EQUIVALENTS	 	 	34,043	 	 	 	160,852	 	
 	 	 	 	 	 	 	 	 	
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	 	 	87,210	 	 	 	154,003	 	

CASH AND CASH EQUIVALENTS AT END OF PERIOD	 	$	121,253	 	 	$	314,855	 	
 	 	 	 	 	 	 	
Supplemental disclosure of cash flow information	 	 	 	 	 	 	 	 	
Cash paid during the period for:	 	 	 	 	 	 	 	 	
Income taxes paid, net of refunds	 	$	38,980	 	 	$	(40	)	
Interest paid, net of amounts capitalized	 	$	50,703	 	 	$	25,526	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements.
 7 

Table of Contents

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, Pinnacle West Energy (dissolved as of August 31, 2006), APS Energy Services, SunCor, El Dorado and Pinnacle West Marketing & Trading. All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with 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. We have condensed certain prior year amounts on our condensed consolidated statements of cash flows to conform to current year presentations.

2.	 	Condensed Consolidated Financial Statements	
     Our unaudited condensed consolidated financial statements reflect all adjustments that we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. We suggest that these condensed consolidated financial statements and notes to condensed consolidated financial statements be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2006 Form 10-K.

3.	 	Quarterly Fluctuations	
     Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate and trading and wholesale marketing activities can have significant impacts on our results for interim periods. For these reasons, results for interim periods do not necessarily represent results to be expected for the year.

4.	 	Changes in Liquidity	
     On January 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its market-based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of long-term debt.
     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions) as of March 31, 2007:
 8 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	
 	 	Consolidated	 	 	 	 	
Year	 	Pinnacle West	 	 	APS	 	
2007	 	$	2	 	 	$	1	 	
2008	 	 	193	 	 	 	1	 	
2009	 	 	1	 	 	 	1	 	
2010	 	 	224	 	 	 	224	 	
2011	 	 	578	 	 	 	401	 	
Thereafter	 	 	2,260	 	 	 	2,260	 	
 	 	 	 	 	 	 	
Total	 	$	3,258	 	 	$	2,888	 	

5.	 	Regulatory Matters	
APS General Rate Case
     On December 15, 2006, hearings concluded in APS’ general rate case before the ACC. APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues, designed to recover the following (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Annual	 	 	 	 	
 	 	Revenue	 	 	Percentage	 	
 	 	Increase	 	 	Increase	 	
Increased fuel and purchased power	 	$	314.4	 	 	 	14.8	%	
Capital structure update	 	 	98.3	 	 	 	4.6	%	
Rate base update, including acquisition of	 	 	 	 	 	 	 	 	
Sundance Plant	 	 	46.2	 	 	 	2.2	%	
Pension funding	 	 	41.3	 	 	 	1.9	%	
Other items	 	 	(65.6	)	 	 	(3.1	)%	

Total increase	 	$	434.6	 	 	 	20.4	%	
 	 	 	 	 	 	 	
     The request is based on (a) a rate base of $4.5 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.0325 per kWh based on estimated 2007 prices; and (c) a capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity). If the ACC approves the requested base rate increase for fuel and purchased power costs, subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates. See “Power Supply Adjustor” below.
     APS has also suggested three additional measures for the ACC’s consideration to improve APS’ financial metrics while benefiting APS’ customers in the long run:

 	•	 	Allowing accelerated depreciation to address the large imbalance between APS’ capital expenditures (estimated to average more than $950 million per year from 2007 through 2009) and its recovery of those expenses (in discussing this measure, APS assumed an increase of $50 million per year in allowed depreciation expense, which would increase APS’ revenue requirement by that same amount);	
 9 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 	•	 	Placing generation and distribution construction work in progress (“CWIP”) in rate base (in discussing this measure, APS assumed the inclusion of its June 30, 2006 CWIP balance of $261 million in rate base, which would increase APS’ revenue requirement by about $33 million); and	
 		
 	•	 	Approving an “attrition adjustment” to provide APS a reasonable opportunity to earn an authorized return on equity given overall cost increases and higher levels of construction needed to accommodate ongoing customer growth (APS suggested a minimum attrition adjustment that would increase the return on equity by 1.7% to 4.1%).	
     The following table summarizes key rate case positions of APS, the ACC staff and the Arizona Residential Utility Consumer Office (“RUCO”), which the Arizona legislature established to represent the interests of residential utility consumers before the ACC:
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	APS (a)	 	 	ACC Staff (b)	 	 	RUCO (b)	 	
 	 	Annual	 	 	 	 	 	 	Annual	 	 	 	 	 	 	Annual	 	 	 	 	
 	 	Revenue	 	 	Percentage	 	 	Revenue	 	 	Percentage	 	 	Revenue	 	 	Percentage	 	
 	 	Increase	 	 	Increase	 	 	Increase	 	 	Increase	 	 	Increase	 	 	Increase	 	
Annual revenue increase (decrease)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Increased fuel and purchased power	 	$	314.4	 	 	 	14.8	%	 	$	193.5	 	 	 	9.2	%	 	$	280.0	 	 	 	13.2	%	
Non-fuel components	 	 	120.2	 	 	 	5.6	%	 	 	(1.0	)	 	 	(0.1	)%	 	 	(68.0	)	 	 	(3.2	)%	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	434.6	 	 	 	20.4	%	 	$	192.5	 	 	 	9.1	%	 	$	212.0	 	 	 	10.0	%	

Base fuel rate (¢kWh)	 	 	3.25	¢	 	 	 	 	 	 	2.80	¢	 	 	 	 	 	 	3.12	¢	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Return on equity	 	 	11.5	%	 	 	 	 	 	 	10.25	%	 	 	 	 	 	 	9.25	%	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Capital structure	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Long-term debt	 	 	45	%	 	 	 	 	 	 	45	%	 	 	 	 	 	 	50	%	 	 	 	 	
Common equity	 	 	55	%	 	 	 	 	 	 	55	%	 	 	 	 	 	 	50	%	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Rate base	 	$4.5 billion	 	 	 	 	 	$4.5 billion	 	 	 	 	 	$4.5 billion	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Test year ended	 	 	9/30/2005	 	 	 	 	 	 	 	9/30/2005	 	 	 	 	 	 	 	9/30/2005	 	 	 	 	 	

(a)	 	APS rejoinder testimony (10/4/06).	
 		
(b)	 	Final position per post-hearing brief and/or final schedules (1/22/07). The ACC staff has also recommended that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.	
     Other intervenors in the rate case include Arizonans for Electric Choice and Competition (“AECC”), a business coalition that advocates on behalf of retail electric customers in Arizona; and
 10 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Phelps Dodge Mining Company (“Phelps Dodge”). In jointly-filed testimony, AECC and Phelps Dodge recommended that the ACC reduce APS’ requested annual increase by at least $134 million.
ALJ Recommended Order
     On April 27, 2007, an ACC ALJ issued a recommended order in connection with the rate case and APS’ application to recover through a PSA surcharge approximately $45 million of deferrals related to unplanned 2005 Palo Verde outages. See “Power Supply Adjustor – PSA Deferrals Related to Unplanned Palo Verde Outages” below.
     The ALJ recommended an increase of approximately $286 million, or 13.5%, in APS’ annual base retail revenues, which includes a fuel-related increase of approximately $280 million and non-fuel related increases of approximately $6 million. The ALJ recommended that the rate increase take effect June 1, 2007, at which time the interim PSA adjustor approved on May 1, 2006 would terminate. See “Interim Rate Increase” below. The ALJ’s recommended rate increase is based on a return on equity of 10.75%; a 45%/55% long-term debt/common equity capital structure; a weighted-average cost of capital of 8.32%; an original cost rate base of $4.4 billion; and a base rate for fuel and purchased power costs of $0.0312 per kWh.
     The ALJ recommended various modifications to the PSA, including the following: (a) the annual PSA adjustor would be established based on projected, rather than historical, fuel and purchased power costs; (b) the 90/10 sharing arrangement under which APS absorbs 10% of retail fuel and purchased power costs above the base rate and retains 10% of the benefit below the base rate would be modified to exclude certain costs, such as renewable energy resources and the fixed element of long-term purchase power agreements acquired through competitive procurement; (c) the cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 per kWh limit to changes in the adjustor rate in any one year would remain in effect; and (d) there would not be a preset annual limit on the amount of fuel and purchased power costs that could be recovered through base rates and the PSA. The ALJ recommended that the modified PSA take effect June 1, 2007 based on the difference between APS’ proposed 2007 projected fuel and purchased power costs of $0.0325 per kWh and the base fuel rate of $0.0312 per kWh.
     The ALJ recommended that the ACC not adopt any of APS’ additional suggestions described above to improve APS’ financial metrics (accelerated depreciation, inclusion of construction work in process in rate base, and an attrition adjustment).
     The ALJ recommended (a) the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the PSA deferrals related to unplanned 2005 Palo Verde outages and (b) the recovery by APS of the balance of the PSA deferrals (approximately $34 million) over a twelve-month period through a temporary PSA surcharge to be effective concurrently with the implementation of new rates. As of May 1, 2007, these deferrals totaled approximately $48 million, including accrued interest. The ALJ also recommended that the ACC require APS and the ACC staff to develop “nuclear performance standards” for the ACC to consider in a separate proceeding. See “PSA Deferrals Related to Palo Verde Unplanned Outages” below.
 11 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
     APS and other parties to the rate case may file exceptions to the recommended order no later than May 15, 2007. APS is currently evaluating the recommended order and expects to file its exceptions to the ALJ’s recommendations by that date. After the exceptions have been filed by APS and the other parties, the ACC will then consider the ALJ’s recommended order and the exceptions. We cannot predict the timing or the outcome of this rate case or the resulting levels of regulated revenues.
Interim Rate Increase
     On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006. APS later reduced this request to $232 million, or approximately 11%, due to a decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase was solely to address APS’ under-collection of higher annual fuel and purchased power costs. On May 2, 2006, the ACC approved an order in this matter that, among other things:

 	•	 	authorized an interim PSA adjustor, effective May 1, 2006, that resulted in an interim retail rate increase of approximately 8.3% designed to recover approximately $138 million of fuel and purchased power costs incurred in 2006 (this interim adjustor, combined with the $15 million PSA surcharge approved by the ACC (see “Surcharge for Certain 2005 PSA Deferrals” below), resulted in a rate increase of approximately 9.0% designed to recover approximately $149 million of fuel and purchased power costs during 2006);	
 		
 	•	 	provided that amounts collected through the interim PSA adjustor “remain subject to a prudency review at the appropriate time” and that “all unplanned Palo Verde outage costs for 2006 should undergo a prudence audit by [the ACC] Staff” (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below);	
 		
 	•	 	encouraged parties to APS’ general rate case to “propose modifications to the PSA that will address on a permanent basis, the issues with timing of recovery when deferrals are large and growing”;	
 		
 	•	 	affirmed APS’ ability to defer fuel and purchased power costs above the prior annual cap of $776.2 million until the ACC decides the general rate case; and	
 		
 	•	 	encouraged APS to diversify its resources “through large scale, sustained energy efficiency programs, [using] low cost renewable energy resources as a hedge against high fossil fuel costs.”	
     On December 8, 2006, the ACC approved APS’ request to continue the interim PSA adjustor until rates become effective as a result of the general rate case.
 12 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Power Supply Adjustor
      PSA Provisions
     The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for adjustment of retail rates to reflect variations in retail fuel and purchased power costs. Such adjustments are to be implemented by use of PSA adjustor rates and PSA surcharges. On January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject to specified parameters and procedures, including the following:

 	•	 	APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the base fuel amount (currently $0.020743 per kWh);	
 		
 	•	 	the deferrals are subject to a 90/10 sharing arrangement in which APS must absorb 10% of the retail fuel and purchased power costs above the base fuel amount and may retain 10% of the benefit from the retail fuel and purchased power costs that are below the base fuel amount;	
 		
 	•	 	amounts to be recovered or refunded through the PSA annual adjustor rate are limited to (a) a cumulative plus or minus $0.004 per kWh from the base fuel amount over the life of the PSA and (b) a maximum plus or minus $0.004 change in the adjustor rate in any one year;	
 		
 	•	 	the recoverable amount of annual retail fuel and purchased power costs through current base rates and the PSA was originally capped at $776.2 million; however, the ACC has removed the cap pending the ACC’s final ruling on APS’ pending request in the general rate case to have the cap eliminated or substantially raised;	
 		
 	•	 	the adjustment is made annually each February 1 st and goes into effect automatically unless suspended by the ACC;	
 		
 	•	 	the PSA will remain in effect for a minimum five-year period, but the ACC may eliminate the PSA at any time, if appropriate, in the event APS files a rate case before the expiration of the five-year period (which APS did by filing the general rate case noted above) or if APS does not comply with the terms of the PSA; and	
 		
 	•	 	APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor rate has been set each year. The amount available for potential PSA surcharges will be limited to the amount of accumulated deferrals through the prior year-end, which are not expected to be recovered through the annual adjustor or any PSA surcharges previously approved by the ACC.	
     2007 PSA Annual Adjustor
     The annual adjustor rate is set for twelve-month periods beginning February 1 of each year. The current PSA annual adjustor rate was set at $0.003987 per kWh effective February 1, 2007, down slightly from the maximum $0.004 annual adjustor rate effective February 1, 2006. The new adjustor rate (a) essentially maintains the approximate 5% retail rate increase that took effect February 1, 2006 as a result of the 2006 PSA Annual Adjustor and
 13 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
which expired on February 1, 2007 and (b) is designed to recover approximately $109 million of deferred fuel and purchased power costs over the twelve-month period that began February 1, 2007.
     Surcharge for Certain 2005 PSA Deferrals
     On April 12, 2006, the ACC approved APS’ request to recover $15 million of 2005 PSA deferrals over a twelve-month period beginning May 2, 2006, representing a temporary rate increase of approximately 0.7%. Approximately $45 million of 2005 PSA deferrals remain subject to a pending application (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below).
     PSA Deferrals Related to Unplanned Palo Verde Outages
     On February 2, 2006, APS filed with the ACC an application to recover approximately $45 million (plus interest) over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. During the course of the pending general rate case, the ACC staff recommended that the ACC disallow approximately $16 million ($10 million after income taxes) of the $45 million request. The ACC staff’s report alleges that four of the eleven Palo Verde outages in 2005 were “avoidable,” three of which resulted in the recommended disallowance. The report also finds, among other things, that:

 	•	 	Three of the outages were due to “faulty or defective vendor supplied equipment” and concludes that APS’ actions were not imprudent in connection with these outages. The report recommends, however, that the ACC evaluate “the degree to which APS has sought appropriate legal or other remedies” in connection with these outages and that APS “be given the opportunity to demonstrate the steps that it has taken in this regard.”	
 		
 	•	 	“Additional investigation will be needed to determine the cause of and responsibility for” the Palo Verde Unit 1 outage resulting from vibration levels in one of the Unit’s shutdown cooling lines.	
     The report also recommends that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.
     APS disagrees with, and has contested, the report’s recommendation that the ACC disallow a portion of the $45 million of PSA deferrals. At the request of the ACC staff, this matter is being addressed by the ACC as part of APS’ pending general rate case. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of these deferrals. See “ALJ Recommended Order” above. APS believes the expenses in question were prudently incurred and, therefore, are recoverable.
     As noted under “Interim Rate Increase” above, the ACC has directed the ACC staff to conduct a “prudence audit” of unplanned 2006 Palo Verde outage costs. This prudence review has not yet been completed. PSA deferrals related to these 2006 outages are estimated to be about $79 million through December 31, 2006. APS believes these expenses were prudently incurred and, therefore, are recoverable.
 14 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
      Proposed Modifications to PSA (Requested In General Rate Case)
     In its pending general rate case, APS has requested the following modifications to the PSA:

 	•	 	The cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 per kWh limit to changes in the adjustor rate in any one year would remain in effect;	
 		
 	•	 	The $776.2 million annual limit on the retail fuel and purchased power costs under APS’ current base rates and the PSA would be removed or increased (although APS may defer fuel and purchased power costs above $776.2 million per year pending the ACC’s final ruling on APS’ pending request to have the cap eliminated or substantially raised);	
 		
 	•	 	The current provision that APS is required to file a surcharge application with the ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100 million would be eliminated, thereby giving APS flexibility in determining when a surcharge filing should be made; and	
 		
 	•	 	The costs of renewable energy and capacity costs attributable to purchased power obtained through competitive procurement would be excluded from the existing 90/10 sharing arrangement under which APS absorbs 10% of the retail fuel and purchased power costs above the base fuel amount and retains 10% of the benefit from retail fuel and purchased power costs that are below the base fuel amount.	
     The ACC staff has recommended the following potential changes to the PSA:

 	•	 	Establishing the PSA annual adjustor, beginning in 2007, based on projected fuel costs rather than historical fuel costs; and	
 		
 	•	 	Removing all existing limitations on fuel cost recovery, including the 90/10 sharing arrangement.	
     The ALJ in the rate case has recommended various modifications to the PSA. See “ALJ Recommended Order” above.
      PSA Balance
     The following table shows the changes in the deferred fuel and purchase power regulatory asset for the three months ended March 31, 2007 and 2006 (dollars in millions):
 15 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Beginning balance	 	$	160	 	 	$	173	 	
Deferred fuel and purchased power costs-current period	 	 	25	 	 	 	13	 	
Interest on deferred fuel	 	 	2	 	 	 	1	 	
Amounts recovered through revenues	 	 	(69	)	 	 	(18	)	
 	 	 	 	 	 	 	
Ending balance	 	$	118	 	 	$	169	 	
 	 	 	 	 	 	 	
Federal
      Price Mitigation Plan
     In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. On February 13, 2006, the FERC increased this price cap to $400 per MWh for prospective sales. Sales at prices above the cap must be justified and are subject to potential refund. We do not expect this price cap to have a material impact on our financial statements.
      FERC Order
     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.
     On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ market-based rate authority in the APS control area (the “April 17 Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.
     As a result of the April 17 Order, the Pinnacle West Companies must charge cost-based rates, rather than market-based rates, in the APS control area for sales occurring after the date of the order, April 17, 2006. The Pinnacle West Companies are required to refund any amounts collected that exceed the default cost-based rates for all market rate sales within the APS control area from February 27, 2005 to April 17, 2006.
     The Pinnacle West Companies filed a Request for Rehearing and Clarification of the April 17 Order on May 17, 2006 and submitted a supplemental compliance filing on July 28, 2006. On December 21, 2006, FERC issued an order granting clarification and provided additional details on
 16 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
what steps the Pinnacle West Companies could take to correct the transmission import study previously submitted. The Pinnacle West Companies complied with this order and filed additional transmission studies and generation market power analyses on February 20, 2007.
     Based upon an analysis of the April 17 Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the April 17 Order will have a material adverse effect on its financial position, results of operations or cash flows.

6.	 	Retirement Plans and Other Benefits	
     Pinnacle West sponsors a qualified defined benefit and account balance pension plan, a nonqualified 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.
     The following table provides details of the plans’ benefit costs for the three months ended March 31, 2007 and 2006. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or capitalized as overhead construction (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pension Benefits	 	 	Other Benefits	 	
 	 	Three Months Ended	 	 	Three Months Ended	 	
 	 	March 31,	 	 	March 31,	 	
 	 	2007	 	 	2006	 	 	2007	 	 	2006	 	
Service cost-benefits earned during the period	 	$	14	 	 	$	15	 	 	$	6	 	 	$	7	 	
Interest cost on benefit obligation	 	 	27	 	 	 	29	 	 	 	10	 	 	 	13	 	
Expected return on plan assets	 	 	(29	)	 	 	(30	)	 	 	(12	)	 	 	(13	)	
Amortization of:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Transition obligation	 	 	—	 	 	 	—	 	 	 	1	 	 	 	1	 	
Prior service cost	 	 	1	 	 	 	1	 	 	 	—	 	 	 	—	 	
Net actuarial loss	 	 	4	 	 	 	7	 	 	 	2	 	 	 	3	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Net periodic benefit cost	 	$	17	 	 	$	22	 	 	$	7	 	 	$	11	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Portion of cost charged to expense	 	$	8	 	 	$	9	 	 	$	3	 	 	$	5	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
APS’ share of costs charged to expense	 	$	7	 	 	$	8	 	 	$	3	 	 	$	4	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Contributions
     The contribution to our pension plan in 2007 is estimated to be approximately $22 million, and the contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $21 million. APS’ share is approximately 97% of both plans.

7.	 	Business Segments	
     Pinnacle West’s two principal business segments are:
 17 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 	•	 	our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and	
 		
 	•	 	our real estate segment, which consists of SunCor’s real estate development and investment activities.	
     Financial data for the three months ended March 31, 2007 and 2006 and at March 31, 2007 and December 31, 2006 by business segment is provided as follows (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Operating Revenues:	 	 	 	 	 	 	 	 	
Regulated electricity	 	$	536	 	 	$	466	 	
Real estate	 	 	77	 	 	 	108	 	
Other	 	 	82	 	 	 	96	 	
 	 	 	 	 	 	 	
Total	 	$	695	 	 	$	670	 	

Net Income (Loss):	 	 	 	 	 	 	 	 	
Regulated electricity	 	$	4	 	 	$	(12	)	
Real estate	 	 	9	 	 	 	22	 	
Other	 	 	4	 	 	 	3	 	
 	 	 	 	 	 	 	
Total	 	$	17	 	 	$	13	 	

 	 	As of	 	 	As of	 	
 	 	March 31, 2007	 	 	December 31, 2006	 	
Assets:	 	 	 	 	 	 	 	 	
Regulated electricity	 	$	10,056	 	 	$	10,566	 	
Real estate	 	 	619	 	 	 	591	 	
Other	 	 	334	 	 	 	299	 	
 	 	 	 	 	 	 	
Total	 	$	11,009	 	 	$	11,456	 	

8.	 	Income Taxes	
     As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2007, it is expected that the IRS will finalize its examination and will issue a settlement on the tax accounting method change. At this time an estimate of the range of reasonably 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
 18 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows.
     We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.
     The total amount of unrecognized tax benefits recorded in accrued taxes as of January 1, 2007 was $186 million, of which $179 million related to APS. The majority of the unrecognized tax benefits relate to the 2001 tax return position described above. Included in the balance of unrecognized tax benefits at January 1, 2007 are approximately $5 million of tax positions for consolidated Pinnacle West that, if recognized, would decrease our effective tax rate. For APS, approximately $3 million would have the same effect.
     We continue to recognize potential accrued interest related to unrecognized tax benefits in the financial statements as income tax expense. As of January 1, 2007, the total amount of accrued interest expense related to uncertain tax positions was $54 million for consolidated Pinnacle West, which is included as a component of the $186 million unrecognized tax benefit noted above. APS’ share included in the total was approximately $53 million. Additionally, Pinnacle West has accrued $9 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS. The application of FIN 48 did not have a material impact for the quarter ended March 31, 2007.
     As of January 1, 2007, the tax year ending December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ending prior to December 31, 1999 may remain subject to examination by state taxing authorities.

9.	 	Variable-Interest Entities	
     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.
     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2007, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 million.
 19 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10.	 	Derivative and Energy Trading Accounting	
     We use derivative instruments (primarily forward purchases and sales, swaps, options and futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of fuel, electricity and emission allowances and credits. As of March 31, 2007, we hedged exposures to the price variability of the power and gas commodities for a maximum of 4.8 years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
Cash Flow Hedges
       The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2007 and 2006 are comprised of the following (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	 	$	911	 	 	$	(178	)	
Losses from the change in options’ time value excluded from measurement of effectiveness	 	 	—	 	 	 	(18	)	
Gains from the discontinuance of cash flow hedges	 	 	314	 	 	 	434	 	
     During the next twelve months ending March 31, 2008, we estimate that a net gain of $76 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).
     Our assets and liabilities from risk management and trading activities are presented in two categories.
     The following tables summarize our assets and liabilities from risk management and trading activities at March 31, 2007 and December 31, 2006 (dollars in thousands):
 20 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Investments	 	 	 	 	 	 	Deferred	 	 	 	 	
 	 	Current	 	 	and Other	 	 	Current	 	 	Credits and	 	 	Net Asset	 	
March 31, 2007	 	Assets	 	 	Assets	 	 	Liabilities	 	 	Other	 	 	(Liability)	 	
Regulated electricity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	$	82,204	 	 	$	84,955	 	 	$	(42,134	)	 	$	(78,680	)	 	$	46,345	 	
Margin account and options	 	 	18,524	 	 	 	—	 	 	 	(1,671	)	 	 	—	 	 	 	16,853	 	
Marketing and trading:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	 	144,622	 	 	 	62,095	 	 	 	(92,192	)	 	 	(29,368	)	 	 	85,157	 	
Options, emission allowances and other – at cost	 	 	108	 	 	 	5,221	 	 	 	(12,830	)	 	 	—	 	 	 	(7,501	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	245,458	 	 	$	152,271	 	 	$	(148,827	)	 	$	(108,048	)	 	$	140,854	 	

 	 	 	 	 	 	Investments	 	 	 	 	 	 	Deferred	 	 	 	 	
 	 	Current	 	 	and Other	 	 	Current	 	 	Credits and	 	 	Net Asset	 	
December 31, 2006	 	Assets	 	 	Assets	 	 	Liabilities	 	 	Other	 	 	(Liability)	 	
Regulated electricity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	$	458,034	 	 	$	96,892	 	 	$	(481,661	)	 	$	(135,056	)	 	$	(61,791	)	
Margin account and options	 	 	77,705	 	 	 	—	 	 	 	(2,228	)	 	 	—	 	 	 	75,477	 	
Marketing and trading:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	 	105,301	 	 	 	69,480	 	 	 	(61,553	)	 	 	(36,114	)	 	 	77,114	 	
Options and emission allowances – at cost	 	 	—	 	 	 	839	 	 	 	(12,753	)	 	 	—	 	 	 	(11,914	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	641,040	 	 	$	167,211	 	 	$	(558,195	)	 	$	(171,170	)	 	$	78,886	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps in the regulated electricity segment. We historically presented the buy side and the sell side of such swaps at fair value gross on our consolidated balance sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset/liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $19 million at March 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $5 million at March 31, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $60 million at March 31, 2007 and $54 million at December 31, 2006, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.
 21 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Credit Risk
     We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 11% of Pinnacle West’s $398 million of risk management and trading assets as of March 31, 2007. Our risk management process assesses and monitors the financial exposure of this and all other counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, including the counterparty discussed above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.
11. Comprehensive Income (Loss)
     Components of comprehensive income (loss) for the three months ended March 31, 2007 and 2006 are as follows (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Net income	 	$	16,530	 	 	$	12,455	 	
 	 	 	 	 	 	 	
Other comprehensive income (loss):	 	 	 	 	 	 	 	 	
Net unrealized gains (losses) on derivative instruments (a)	 	 	62,560	 	 	 	(204,983	)	
Net reclassification of realized gains to income (b)	 	 	(5,013	)	 	 	(17,530	)	
Reclassification of pension and other postretirement benefits to income	 	 	251	 	 	 	—	 	
Income tax benefit (expense) related to items of other comprehensive income (loss)	 	 	(22,570	)	 	 	86,891	 	
 	 	 	 	 	 	 	
Total other comprehensive income (loss)	 	 	35,228	 	 	 	(135,622	)	
 	 	 	 	 	 	 	
Comprehensive income (loss)	 	$	51,758	 	 	$	(123,167	)	

			
(a)	 	These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.	
 22 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(b)	 	These amounts primarily include the reclassification of unrealized gains and losses to realized for contracted commodities delivered during the period.	
12. Commitments and Contingencies
Palo Verde Nuclear Generating Station
      Spent Nuclear Fuel and Waste Disposal
     Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.
     APS currently estimates it will incur $147 million (in 2006 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2007, APS had a regulatory liability of $2.8 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.
      NRC Inspection
     In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator started but did not provide electrical output during routine inspections on July 25 and September 22, 2006.
     On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) for this matter. In connection with its finding, the NRC stated that it would “use the NRC Action Matrix to determine the most appropriate response and any increase in NRC oversight, or actions [APS needs] to take in response to the most recent performance deficiencies” and notify APS of its determination at a later date. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix, which will result in an enhanced NRC inspection regimen. APS continues to implement its plan to improve Palo Verde’s operational performance.
 23 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
California Energy Market Issues and Refunds in the Pacific Northwest
      FERC
     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.
     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On October 10, 2006, the State of California filed a motion to stay the issuance of the mandate (scheduled to be issued on November 2, 2006) until June 13, 2007. The request for stay was granted. The outcome of the further proceedings cannot be predicted at this time.
     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals and oral argument was held on January 8, 2007. Although the FERC ruling in this matter is being appealed
 24 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or cash flows.
     On March 26, 2003, the FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.
FERC Order
     See “FERC Order” in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.
Natural Gas Supply
     Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation were subject to a rate moratorium through December 31, 2005.
     On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the cost responsibility associated with the changed contractual obligations in a way that would be less favorable to APS than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS’ annual capacity cost could be increased by approximately $3 million per year after income taxes for the period September 2003 through December 2005. This appeal had been stayed pending further consideration by the FERC. On May 26, 2006, the FERC issued an Order on Remand affirming its earlier decision that there is no basis for modifying the settlement rates during the remaining term of the settlement. The party seeking appellate review is continuing to pursue an appeal of this issue and has therefore sought rehearing of the May 26, 2006 order. The FERC’s next status report is due to the DC Circuit Court of Appeals by August 7, 2007.
Navajo Nation Litigation
     In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating
 25 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.
     In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.
Superfund
     Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52 nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.
Litigation
     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our results of operations, cash flows or liquidity.
13. Nuclear Insurance
     The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.
 26 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
     The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $18.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.
14. Other Income and Other Expense
     The following table provides detail of other income and other expense for the three months ended March 31, 2007 and 2006 (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Other income:	 	 	 	 	 	 	 	 	
Interest income	 	$	3,413	 	 	$	4,905	 	
SunCor other income (a)	 	 	579	 	 	 	166	 	
Miscellaneous	 	 	520	 	 	 	396	 	
 	 	 	 	 	 	 	
Total other income	 	$	4,512	 	 	$	5,467	 	

Other expense:	 	 	 	 	 	 	 	 	
Non-operating costs (b)	 	$	(3,311	)	 	$	(3,719	)	
Investment losses – net	 	 	(1,739	)	 	 	(31	)	
Miscellaneous	 	 	(1,303	)	 	 	(791	)	
 	 	 	 	 	 	 	
Total other expense	 	$	(6,353	)	 	$	(4,541	)	

			
(a)	 	Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.	
 		
(b)	 	As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).	
15. Guarantees
     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to commodity energy products. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle
 27 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
     West’s current outstanding guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2007 are as follows (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Guarantees	 	 	Surety Bonds	 	
 	 	 	 	 	 	Term	 	 	 	 	 	 	Term	 	
 	 	Amount	 	 	(in years)	 	 	Amount	 	 	(in years)	 	
Parental:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Pinnacle West Marketing & Trading	 	$	63	 	 	 	1	 	 	$	—	 	 	 	—	 	
APS Energy Services	 	 	15	 	 	 	1	 	 	 	19	 	 	 	1	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	78	 	 	 	 	 	 	$	19	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     At March 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in late 2007. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
     APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2007, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $86 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at March 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2007. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.
     We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.
16. Earnings Per Share
     The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2007 and 2006:
 28 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Basic earnings per share:	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.16	 	 	$	0.12	 	
Income from discontinued operations	 	 	0.01	 	 	 	0.01	 	
 	 	 	 	 	 	 	
Earnings per share – basic	 	$	0.17	 	 	$	0.13	 	

Diluted earnings per share:	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	0.16	 	 	$	0.12	 	
Income from discontinued operations	 	 	—	 	 	 	0.01	 	
 	 	 	 	 	 	 	
Earnings per share – diluted	 	$	0.16	 	 	$	0.13	 	
 	 	 	 	 	 	 	
     Dilutive stock options and performance shares increased average common shares outstanding by approximately 577,000 shares and 334,000 shares for the three months ended March 31, 2007 and March 31, 2006, respectively.
     For the three-month period ended March 31, 2007, there were no outstanding options to purchase shares excluded from the computation of earnings per share because the options’ exercise prices were less than the average market price of the common shares. Options to purchase shares of common stock that were excluded from the computation of diluted earnings per share were 747,874 shares for the three-month period ended March 31, 2006.
17. Discontinued Operations
      SunCor (real estate segment) – In 2006 and 2007, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. The following table contains SunCor’s revenue, income before income taxes and income after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2007 and 2006 (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Revenue	 	$	2	 	 	$	1	 	
Income before income taxes	 	 	1	 	 	 	1	 	
Income after income taxes	 	 	1	 	 	 	1	 	
18. Nuclear Decommissioning Trust
     To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we
 29 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of unrealized gains (losses) on investment securities in other regulatory liabilities/assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at March 31, 2007 and December 31, 2006 (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Total Unrealized	 	
 	 	Fair Value	 	 	Gains	 	
March 31, 2007	 	 	 	 	 	 	 	 	
Equity securities	 	$	167	 	 	$	63	 	
Fixed income securities	 	 	182	 	 	 	3	 	
 	 	 	 	 	 	 	
Total	 	$	349	 	 	$	66	 	

December 31, 2006	 	 	 	 	 	 	 	 	
Equity securities	 	$	164	 	 	$	63	 	
Fixed income securities	 	 	180	 	 	 	3	 	
 	 	 	 	 	 	 	
Total	 	$	344	 	 	$	66	 	
 	 	 	 	 	 	 	
     The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	
 	 	March 31,	
 	 	2007	 	2006	
Realized gains	 	$	1	 	 	$	1	 	
Realized losses	 	 	(1	)	 	 	(1	)	
Proceeds from the sale of securities	 	 	63	 	 	 	34	 	
     The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2007 is as follows (dollars in millions):
 	 	 	 	 	
Fair Value	 	March 31, 2007	 	
Less than one year	 	$	15	 	
1 year - 5 years	 	 	41	 	
5 years - 10 years	 	 	41	 	
Greater than 10 years	 	 	85	 	
 	 	 	 	
Total	 	$	182	 	
 	 	 	 	
19. New Accounting Standards
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance.
 30 

Table of Contents

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance.
     See Note 8 for a discussion of FASB Interpretation No. 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial.
 31 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
ELECTRIC OPERATING REVENUES	 	 	 	 	 	 	 	 	
Regulated electricity	 	$	537,376	 	 	$	467,222	 	
Marketing and trading	 	 	884	 	 	 	9,647	 	
 	 	 	 	 	 	 	
Total	 	 	538,260	 	 	 	476,869	 	

OPERATING EXPENSES	 	 	 	 	 	 	 	 	
Regulated electricity fuel and purchased power	 	 	204,494	 	 	 	158,274	 	
Marketing and trading fuel and purchased power	 	 	1,702	 	 	 	1,368	 	
Operations and maintenance	 	 	165,934	 	 	 	173,353	 	
Depreciation and amortization	 	 	87,876	 	 	 	86,311	 	
Income taxes	 	 	3,143	 	 	 	(3,029	)	
Other taxes	 	 	34,522	 	 	 	35,548	 	
 	 	 	 	 	 	 	
Total	 	 	497,671	 	 	 	451,825	 	
 	 	 	 	 	 	 	
OPERATING INCOME	 	 	40,589	 	 	 	25,044	 	

OTHER INCOME (DEDUCTIONS)	 	 	 	 	 	 	 	 	
Income taxes	 	 	754	 	 	 	236	 	
Allowance for equity funds used during construction	 	 	4,444	 	 	 	3,801	 	
Other income (Note S-3)	 	 	4,433	 	 	 	4,806	 	
Other expense (Note S-3)	 	 	(4,904	)	 	 	(3,680	)	
 	 	 	 	 	 	 	
Total	 	 	4,727	 	 	 	5,163	 	

INTEREST DEDUCTIONS	 	 	 	 	 	 	 	 	
Interest on long-term debt	 	 	40,075	 	 	 	34,250	 	
Interest on short-term borrowings	 	 	1,981	 	 	 	2,026	 	
Debt discount, premium and expense	 	 	1,156	 	 	 	1,173	 	
Allowance for borrowed funds used during construction	 	 	(2,213	)	 	 	(1,721	)	
 	 	 	 	 	 	 	
Total	 	 	40,999	 	 	 	35,728	 	

NET INCOME (LOSS)	 	$	4,317	 	 	$	(5,521	)	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.
 32 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	March 31,	 	 	December 31,	 	
 	 	2007	 	 	2006	 	
ASSETS	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
UTILITY PLANT	 	 	 	 	 	 	 	 	
Electric plant in service and held for future use	 	$	11,195,376	 	 	$	11,094,868	 	
Less accumulated depreciation and amortization	 	 	3,843,518	 	 	 	3,789,534	 	
 	 	 	 	 	 	 	
Net	 	 	7,351,858	 	 	 	7,305,334	 	
 	 	 	 	 	 	 	 	 	
Construction work in progress	 	 	419,639	 	 	 	365,704	 	
Intangible assets, net of accumulated amortization	 	 	89,775	 	 	 	95,601	 	
Nuclear fuel, net of accumulated amortization	 	 	69,539	 	 	 	60,100	 	
 	 	 	 	 	 	 	
Total utility plant	 	 	7,930,811	 	 	 	7,826,739	 	

INVESTMENTS AND OTHER ASSETS	 	 	 	 	 	 	 	 	
Decommissioning trust accounts (Note 18)	 	 	349,470	 	 	 	343,771	 	
Assets from long-term risk management and trading activities (Note S-1)	 	 	84,955	 	 	 	96,892	 	
Other assets	 	 	68,389	 	 	 	67,763	 	
 	 	 	 	 	 	 	
Total investments and other assets	 	 	502,814	 	 	 	508,426	 	

CURRENT ASSETS	 	 	 	 	 	 	 	 	
Cash and cash equivalents	 	 	102,564	 	 	 	81,870	 	
Investment in debt securities	 	 	—	 	 	 	32,700	 	
Customer and other receivables	 	 	303,790	 	 	 	410,436	 	
Allowance for doubtful accounts	 	 	(3,834	)	 	 	(4,223	)	
Materials and supplies (at average cost)	 	 	137,357	 	 	 	125,802	 	
Fossil fuel (at average cost)	 	 	24,856	 	 	 	21,973	 	
Assets from risk management and trading activities (Note S-1)	 	 	105,278	 	 	 	539,308	 	
Deferred income taxes	 	 	11,763	 	 	 	19,220	 	
Other current assets	 	 	13,821	 	 	 	13,367	 	
 	 	 	 	 	 	 	
Total current assets	 	 	695,595	 	 	 	1,240,453	 	

DEFERRED DEBITS	 	 	 	 	 	 	 	 	
Deferred fuel and purchased power regulatory asset (Note 5)	 	 	117,795	 	 	 	160,268	 	
Other regulatory assets	 	 	625,480	 	 	 	686,016	 	
Unamortized debt issue costs	 	 	25,869	 	 	 	26,393	 	
Other (Note 8)	 	 	131,319	 	 	 	65,397	 	
 	 	 	 	 	 	 	
Total deferred debits	 	 	900,463	 	 	 	938,074	 	

TOTAL ASSETS	 	$	10,029,683	 	 	$	10,513,692	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.
 33 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	March 31,	 	 	December 31,	 	
 	 	2007	 	 	2006	 	
LIABILITIES AND EQUITY	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
CAPITALIZATION	 	 	 	 	 	 	 	 	
Common stock	 	$	178,162	 	 	$	178,162	 	
Additional paid-in capital	 	 	2,065,918	 	 	 	2,065,918	 	
Retained earnings	 	 	924,434	 	 	 	960,405	 	
Accumulated other comprehensive income:	 	 	 	 	 	 	 	 	
Derivative instruments	 	 	34,150	 	 	 	2,988	 	
 	 	 	 	 	 	 	
Common stock equity	 	 	3,202,664	 	 	 	3,207,473	 	
Long-term debt less current maturities	 	 	2,877,377	 	 	 	2,877,502	 	
 	 	 	 	 	 	 	
Total capitalization	 	 	6,080,041	 	 	 	6,084,975	 	

CURRENT LIABILITIES	 	 	 	 	 	 	 	 	
Current maturities of long-term debt	 	 	1,049	 	 	 	968	 	
Accounts payable	 	 	136,800	 	 	 	223,417	 	
Accrued taxes (Note 8)	 	 	425,641	 	 	 	381,444	 	
Accrued interest	 	 	39,304	 	 	 	45,254	 	
Common dividends payable	 	 	42,500	 	 	 	—	 	
Customer deposits	 	 	64,571	 	 	 	61,900	 	
Liabilities from risk management and trading activities (Note S-1)	 	 	51,962	 	 	 	490,855	 	
Other current liabilities	 	 	71,404	 	 	 	74,728	 	
 	 	 	 	 	 	 	
Total current liabilities	 	 	833,231	 	 	 	1,278,566	 	

DEFERRED CREDITS AND OTHER	 	 	 	 	 	 	 	 	
Deferred income taxes	 	 	1,226,020	 	 	 	1,215,862	 	
Regulatory liabilities	 	 	646,424	 	 	 	635,431	 	
Liability for asset retirements	 	 	270,264	 	 	 	268,389	 	
Pension and other postretirement liabilities (Note 6)	 	 	562,088	 	 	 	551,531	 	
Customer advances for construction	 	 	74,684	 	 	 	71,211	 	
Unamortized gain – sale of utility plant	 	 	40,038	 	 	 	41,182	 	
Liabilities from long-term risk management and trading activities (Note S-1)	 	 	78,680	 	 	 	135,056	 	
Other	 	 	218,213	 	 	 	231,489	 	
 	 	 	 	 	 	 	
Total deferred credits and other	 	 	3,116,411	 	 	 	3,150,151	 	

COMMITMENTS AND CONTINGENCIES (NOTES 5, 8, 12, 13 and 15)	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	
TOTAL LIABILITIES AND EQUITY	 	$	10,029,683	 	 	$	10,513,692	 	
 	 	 	 	 	 	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.
 34 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
CASH FLOWS FROM OPERATING ACTIVITIES	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	4,317	 	 	$	(5,521	)	
Adjustments to reconcile net income (loss) to net cash provided by operating activities:	 	 	 	 	 	 	 	 	
Depreciation and amortization including nuclear fuel	 	 	96,974	 	 	 	93,762	 	
Deferred fuel and purchased power	 	 	(26,293	)	 	 	(14,538	)	
Deferred fuel and purchased power amortization	 	 	68,766	 	 	 	17,808	 	
Allowance for equity funds used during construction	 	 	(4,444	)	 	 	(3,801	)	
Deferred income taxes	 	 	(15,566	)	 	 	1,757	 	
Changes in mark-to-market valuations	 	 	(3,507	)	 	 	974	 	
Changes in current assets and liabilities:	 	 	 	 	 	 	 	 	
Customer and other receivables	 	 	128,030	 	 	 	124,568	 	
Materials, supplies and fossil fuel	 	 	(14,438	)	 	 	(1,101	)	
Other current assets	 	 	(2,112	)	 	 	4,892	 	
Accounts payable	 	 	(92,004	)	 	 	(62,543	)	
Accrued taxes	 	 	6,673	 	 	 	30,343	 	
Collateral	 	 	1,789	 	 	 	(150,640	)	
Other current liabilities	 	 	(6,533	)	 	 	32,231	 	
Change in risk management and trading – assets	 	 	59,181	 	 	 	2,189	 	
Change in risk management and trading – liabilities	 	 	(557	)	 	 	(65,131	)	
Change in other long-term assets	 	 	(21,108	)	 	 	(7,524	)	
Change in other long-term liabilities	 	 	6,284	 	 	 	11,366	 	
 	 	 	 	 	 	 	
Net cash flow provided by operating activities	 	 	185,452	 	 	 	9,091	 	

CASH FLOWS FROM INVESTING ACTIVITIES	 	 	 	 	 	 	 	 	
Capital expenditures	 	 	(188,947	)	 	 	(140,185	)	
Allowance for borrowed funds used during construction	 	 	(2,213	)	 	 	(1,721	)	
Purchases of investment securities	 	 	(36,525	)	 	 	(122,025	)	
Proceeds from sale of investment securities	 	 	69,225	 	 	 	122,025	 	
Proceeds from nuclear decommissioning trust sales	 	 	63,490	 	 	 	33,743	 	
Investment in nuclear decommissioning trust	 	 	(68,675	)	 	 	(38,929	)	
Other	 	 	(826	)	 	 	(1,966	)	
 	 	 	 	 	 	 	
Net cash flow used for investing activities	 	 	(164,471	)	 	 	(149,058	)	

CASH FLOWS FROM FINANCING ACTIVITIES	 	 	 	 	 	 	 	 	
Equity infusion	 	 	—	 	 	 	210,000	 	
Dividends paid on common stock	 	 	—	 	 	 	(42,500	)	
Repayment and reacquisition of long-term debt	 	 	(287	)	 	 	(821	)	
 	 	 	 	 	 	 	
Net cash flow provided by (used for) financing activities	 	 	(287	)	 	 	166,679	 	

NET INCREASE IN CASH AND CASH EQUIVALENTS	 	 	20,694	 	 	 	26,712	 	
 	 	 	 	 	 	 	 	 	
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	 	 	81,870	 	 	 	49,933	 	

CASH AND CASH EQUIVALENTS AT END OF PERIOD	 	$	102,564	 	 	$	76,645	 	
 	 	 	 	 	 	 	
Supplemental disclosure of cash flow information:	 	 	 	 	 	 	 	 	
Cash paid during the year for:	 	 	 	 	 	 	 	 	
Income taxes, net of refunds	 	$	44,088	 	 	$	—	 	
Interest, net of amounts capitalized	 	$	45,793	 	 	$	24,297	 	
See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.
 35 

Table of Contents

     Certain notes to APS’ Condensed Financial Statements are combined with the Notes to Pinnacle West’s Condensed Consolidated Financial Statements. Listed below are the Condensed Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS’ Condensed Financial Statements. In addition, listed below are the Supplemental Notes which are required disclosures for APS and should be read in conjunction with Pinnacle West’s Condensed Consolidated Notes.
 	 	 	 	 	
 	 	Condensed	 	APS’	
 	 	Consolidated	 	Supplemental	
 	 	Footnote	 	Footnote	
 	 	Reference	 	Reference	
Consolidation and Nature of Operations	 	Note 1	 	—	
Condensed Consolidated Financial Statements	 	Note 2	 	—	
Quarterly Fluctuations	 	Note 3	 	—	
Changes in Liquidity	 	Note 4	 	—	
Regulatory Matters	 	Note 5	 	—	
Retirement Plans and Other Benefits	 	Note 6	 	—	
Business Segments	 	Note 7	 	—	
Income Taxes	 	Note 8	 	—	
Variable Interest Entities	 	Note 9	 	—	
Derivative and Energy Trading Accounting	 	Note 10	 	Note S-1	
Comprehensive Income (Loss)	 	Note 11	 	Note S-2	
Commitments and Contingencies	 	Note 12	 	—	
Nuclear Insurance	 	Note 13	 	—	
Other Income and Other Expense	 	Note 14	 	Note S-3	
Guarantees	 	Note 15	 	—	
Earnings Per Share	 	Note 16	 	—	
Discontinued Operations	 	Note 17	 	—	
Nuclear Decommissioning Trust	 	Note 18	 	—	
New Accounting Standards	 	Note 19	 	—	
 36 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-1. Derivative and Energy Trading Accounting
     APS is exposed to the impact of market fluctuations in the commodity price of electricity, natural gas and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels, and emission allowances and credits. As of March 31, 2007, APS hedged exposures to these risks for a maximum of 4.8 years.
Cash Flow Hedges
     The changes in the fair value of APS’ hedged positions included in the APS Condensed Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2007 and 2006 were comprised of the following (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	
 	 	March 31,	
 	 	2007	 	2006	
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	 	$	911	 	 	$	(436	)	
Losses from the change in options’ time value excluded from measurement of effectiveness	 	 	—	 	 	 	(18	)	
Gains from the discontinuance of cash flow hedges	 	 	150	 	 	 	159	 	
     During the next twelve months ending March 31, 2008, APS estimates that a net gain of $39 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).
     APS’ assets and liabilities from risk management and trading activities are presented in two categories.
     The following tables summarize APS’ assets and liabilities from risk management and trading activities at March 31, 2007 and December 31, 2006 (dollars in thousands):
 37 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	Investments	 	 	 	 	 	 	Deferred	 	 	 	 	
 	 	Current	 	 	and Other	 	 	Current	 	 	Credits and	 	 	Net Asset	 	
March 31, 2007	 	Assets	 	 	Assets	 	 	Liabilities	 	 	Other	 	 	(Liability)	 	
Regulated Electricity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	$	82,204	 	 	$	84,955	 	 	$	(42,134	)	 	$	(78,680	)	 	$	46,345	 	
Margin account and options	 	 	18,524	 	 	 	—	 	 	 	(1,671	)	 	 	—	 	 	 	16,853	 	
Marketing and Trading:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	 	4,550	 	 	 	—	 	 	 	(7,845	)	 	 	—	 	 	 	(3,295	)	
Options at cost	 	 	—	 	 	 	—	 	 	 	(312	)	 	 	—	 	 	 	(312	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	105,278	 	 	$	84,955	 	 	$	(51,962	)	 	$	(78,680	)	 	$	59,591	 	

 	 	 	 	 	 	Investments	 	 	 	 	 	 	Deferred	 	 	 	 	
 	 	Current	 	 	and Other	 	 	Current	 	 	Credits and	 	 	Net Asset	 	
December 31, 2006	 	Assets	 	 	Assets	 	 	Liabilities	 	 	Other	 	 	(Liability)	 	
Regulated Electricity:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	$	458,034	 	 	$	96,892	 	 	$	(481,661	)	 	$	(135,056	)	 	$	(61,791	)	
Margin account and options	 	 	77,705	 	 	 	—	 	 	 	(2,228	)	 	 	—	 	 	 	75,477	 	
Marketing and Trading:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market	 	 	3,569	 	 	 	—	 	 	 	(6,654	)	 	 	—	 	 	 	(3,085	)	
Options at cost	 	 	—	 	 	 	—	 	 	 	(312	)	 	 	—	 	 	 	(312	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	539,308	 	 	$	96,892	 	 	$	(490,855	)	 	$	(135,056	)	 	$	10,289	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps in the regulated electricity segment. We historically presented the buy side and the sell side of such swaps at fair value gross on our consolidated balance sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset/liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.
     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $19 million at March 31, 2007 and $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.
     Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. No collateral was provided to counterparties at March 31, 2007 and $2 million was provided at December 31, 2006 and is included in other current assets on the Condensed Balance Sheets. Collateral provided to us by counterparties was $1 million at both March 31, 2007 and December 31, 2006, and is included in other current liabilities on the Condensed Balance Sheets.
 38 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS
S-2. Comprehensive Income (Loss)
     Components of APS’ comprehensive income (loss) for the three months ended March 31, 2007 and 2006 are as follows (dollars in thousands):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Net income (loss)	 	$	4,317	 	 	$	(5,521	)	
 	 	 	 	 	 	 	
Other comprehensive income (loss):	 	 	 	 	 	 	 	 	
Net unrealized gains (losses) on derivative instruments (a)	 	 	50,545	 	 	 	(162,892	)	
Net reclassification of realized losses (gains) to income (b)	 	 	741	 	 	 	(10,116	)	
Net income tax benefit (expense) related to items of other comprehensive income (loss)	 	 	(20,124	)	 	 	67,560	 	
 	 	 	 	 	 	 	
Total other comprehensive income (loss)	 	 	31,162	 	 	 	(105,448	)	
 	 	 	 	 	 	 	
Comprehensive income (loss)	 	$	35,479	 	 	$	(110,969	)	

			
(a)	 	These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and natural gas requirements to serve Native Load. These changes are primarily due to changes in forward natural gas prices and wholesale electricity prices.	
 		
(b)	 	These amounts primarily include the reclassification of unrealized gains and losses to realized gains and losses for contracted commodities delivered during the period.	
S-3. Other Income and Other Expense
     The following table provides detail of APS’ other income and other expense for the three months ended March 31, 2007 and 2006 (dollars in thousands):
 39 

Table of Contents

 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Other income:	 	 	 	 	 	 	 	 	
Interest income	 	$	3,347	 	 	$	3,534	 	
Investment gains – net	 	 	377	 	 	 	875	 	
Miscellaneous	 	 	709	 	 	 	397	 	
 	 	 	 	 	 	 	
Total other income	 	$	4,433	 	 	$	4,806	 	

Other expense:	 	 	 	 	 	 	 	 	
Non-operating costs (a)	 	$	(3,233	)	 	$	(3,216	)	
Asset dispositions	 	 	(1,081	)	 	 	(196	)	
Miscellaneous	 	 	(590	)	 	 	(268	)	
 	 	 	 	 	 	 	
Total other expense	 	$	(4,904	)	 	$	(3,680	)	

			
(a)	 	As defined by the FERC, includes below-the-line non-operating utility income and expense (items excluded from utility rate recovery).	
 40 

Table of Contents
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
     The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and Arizona Public Service Company’s Condensed Financial Statements and the related Notes that appear in Item 1 of this report.
OVERVIEW
     Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.
     The ACC regulates APS’ retail electric rates. The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, these proceedings consist of:

 	•	 	a general retail rate case pursuant to which APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues;	
 		
 	•	 	an application for a temporary rate increase of approximately 1.9%, through a PSA surcharge, to recover $45 million in retail fuel and purchased power costs relating to Palo Verde’s 2005 unplanned outages that were deferred by APS in 2005 under the PSA and are subject to the ACC’s completion of an inquiry regarding the outages (this matter is now being addressed in the general retail rate case); and	
 		
 	•	 	the ACC’s prudency review of amounts collected through the May 2, 2006 interim PSA adjustor (see “Interim Rate Increase” in Note 5) related to unplanned 2006 Palo Verde outages.	
     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures. Pinnacle West Marketing & Trading is the Company’s newly-formed marketing and trading subsidiary. Activity in this subsidiary began in February 2007. See Note 4.
     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.
 41 

Table of Contents

     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.
EARNINGS CONTRIBUTION BY BUSINESS SEGMENT
     Pinnacle West’s two principal business segments are:

 	•	 	our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electric service to Native Load customers) and related activities and includes electricity generation, transmission and distribution; and	
 		
 	•	 	our real estate segment, which consists of SunCor’s real estate development and investment activities.	
     The following table summarizes income from continuing operations by segment for the three months ended March 31, 2007 and 2006 and reconciles net income in total (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	
 	 	March 31,	 	
 	 	2007	 	 	2006	 	
Regulated electricity	 	$	4	 	 	$	(12	)	
Real estate	 	 	8	 	 	 	21	 	
Other (a)	 	 	4	 	 	 	3	 	
 	 	 	 	 	 	 	
Income from continuing operations	 	 	16	 	 	 	12	 	
Discontinued operations – net of tax:	 	 	 	 	 	 	 	 	
Real estate	 	 	1	 	 	 	1	 	
 	 	 	 	 	 	 	
Net income	 	$	17	 	 	$	13	 	

			
(a)	 	Primarily marketing and trading activity.	
PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS
General
     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment, gross margin refers to operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.1 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses.
Deferred Fuel and Purchased Power Costs
     Our subsidiary, APS, settled its 2003 general retail rate case effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund
 42 

Table of Contents

fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications. See “Power Supply Adjustor” in Note 5.
     Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates, primarily due to the use of higher cost resources and higher fuel prices, and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA accumulated unrecovered deferrals at March 31, 2007 was approximately $118 million. The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power.
     APS recorded PSA deferrals of (a) $45 million related to replacement power costs in 2005 associated with unplanned Palo Verde outages and (b) $79 million related to replacement power costs in 2006 associated with unplanned outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages and reduced power operations are the subject of ACC prudence reviews. The ACC staff has completed its prudence review of 2005 unplanned outages and has recommended disallowance of $16 million of the 2005 costs. The recommendation is being considered as part of APS’ general rate case currently pending before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 5. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the deferrals related to the unplanned 2005 Palo Verde outages. See “ALJ Recommended Order” in Note 5. Neither the ACC staff recommendation nor the ALJ recommendation changes management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable. The prudence review of 2006 unplanned outages has not yet been completed.
Operating Results – Three-month period ended March 31, 2007 compared with three-month period ended March 31, 2006
     Our consolidated net income for the three months ended March 31, 2007 was $17 million compared with $13 million for the comparable prior-year period. Net income increased $4 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

 	•	 	Regulated Electricity Segment – Net income increased approximately $16 million primarily due to the effects of cooler weather on retail sales; higher retail sales due to customer growth; and lower operations and maintenance expense related to generation. In addition, higher fuel and purchased power costs were partially offset by the deferral of such costs in accordance with the PSA. See “Deferred Fuel and Purchased Power Costs” above.	
 		
 	•	 	Real Estate Segment – Net income decreased approximately $13 million primarily due to lower sales of land parcels and residential property.	
 		
 	•	 	Other miscellaneous items, net, increased approximately $1 million.	
 43 

Table of Contents

Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Increase (Decrease)	 	
 	 	Pretax	 	 	After Tax	 	
Regulated electricity segment gross margin:	 	 	 	 	 	 	 	 	
Effects of cooler weather on retail sales	 	$	13	 	 	$	8	 	
Higher retail sales due to customer growth, excluding weather effects	 	 	10	 	 	 	6	 	
Higher fuel and purchased power costs due to increased prices (see “Deferred Fuel and Purchased Power Costs” above)	 	 	(14	)	 	 	(9	)	
Increased deferred fuel and purchased power costs	 	 	12	 	 	 	7	 	
Miscellaneous items, net	 	 	3	 	 	 	3	 	
 	 	 	 	 	 	 	
Net increase in regulated electricity segment gross margin	 	 	24	 	 	 	15	 	
Lower real estate segment contribution primarily due to decreased sales of land parcels and residential property	 	 	(21	)	 	 	(13	)	
Operations and maintenance decreases primarily due to:	 	 	 	 	 	 	 	 	
Generation costs, including fewer power plant maintenance outages	 	 	4	 	 	 	2	 	
Miscellaneous items, net	 	 	3	 	 	 	2	 	
Other miscellaneous items, net	 	 	(4	)	 	 	(2	)	
 	 	 	 	 	 	 	
Net increase in net income	 	$	6	 	 	$	4	 	
 	 	 	 	 	 	 	
Regulated Electricity Segment Revenues
     Regulated electricity segment revenues were $70 million higher for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

 	•	 	a $51 million increase in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);	
 		
 	•	 	an $18 million increase in retail revenues due to cooler weather;	
 		
 	•	 	a $13 million increase in retail revenues related to customer growth, excluding weather effects;	
 		
 	•	 	a $5 million decrease in Off-System Sales due to lower sales volumes; and	
 		
 	•	 	a $7 million decrease due to miscellaneous factors.	
Real Estate Segment Revenues
     Real estate segment revenues were $31 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

 	•	 	a $20 million decrease in residential sales due to a slowdown in the western United States residential real estate markets;	
 44 

Table of Contents

 	•	 	a $15 million decrease in revenue primarily due to a significant land parcel sale in 2006 without a comparable sale in 2007; and	
 		
 	•	 	a $4 million increase due to miscellaneous factors.	
Other Revenues
     Marketing and trading revenues were $13 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

 	•	 	an $11 million decrease from lower competitive retail sales volumes in California; and	
 		
 	•	 	a $2 million decrease due to miscellaneous factors.	
LIQUIDITY AND CAPITAL RESOURCES
Capital Needs and Resources – Pinnacle West Consolidated
      Capital Expenditure Requirements
     The following table summarizes the actual capital expenditures for the three months ended March 31, 2007 and estimated capital expenditures for the next three years (dollars in millions):
CAPITAL EXPENDITURES
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	 	Estimated for the Year Ended	 	
 	 	March 31,	 	 	December 31,	 	
 	 	2007	 	 	2007	 	 	2008	 	 	2009	 	
APS	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Distribution	 	$	97	 	 	$	362	 	 	$	411	 	 	$	459	 	
Transmission	 	 	40	 	 	 	173	 	 	 	200	 	 	 	288	 	
Generation	 	 	45	 	 	 	388	 	 	 	298	 	 	 	335	 	
Other (a)	 	 	1	 	 	 	26	 	 	 	39	 	 	 	40	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Subtotal	 	 	183	 	 	 	949	 	 	 	948	 	 	 	1,122	 	
SunCor (b)	 	 	39	 	 	 	131	 	 	 	101	 	 	 	100	 	
Other	 	 	1	 	 	 	13	 	 	 	19	 	 	 	10	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	223	 	 	$	1,093	 	 	$	1,068	 	 	$	1,232	 	

			
(a)	 	Primarily information systems and facilities projects.	
 		
(b)	 	Consists primarily of capital expenditures for residential land development and retail and office building construction reflected in “Real estate investments” on the Condensed Consolidated Statements of Cash Flows.	
     Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and
 45 

Table of Contents

facility costs. Examples of the types of projects included in the forecast include lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth.
     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Environmental expenditures are estimated at approximately $80 million to $100 million per year for 2007, 2008 and 2009. Generation also includes nuclear fuel expenditures of approximately $110 million for 2007, $40 million for 2008 and $100 million for 2009.
     The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit 3 and are scheduled for completion in the Fall of 2007 at an approximate cost of $70 million (APS’ share). Approximately $30 million of the Unit 3 steam generator costs have been incurred through March 31, 2007, with the remaining $40 million included in the capital expenditures table above. Capital expenditures will be funded with internally generated cash and/or external financings.
      Contractual Obligations
     Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.6 billion at December 31, 2006 to $2.8 billion at March 31, 2007 as follows (dollars in billions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2007	 	2008-2009	 	2010-2011	 	Thereafter	 	Total	
$0.5	 	$	0.5	 	 	$	0.5	 	 	$	1.3	 	 	$	2.8	 	
     See Note 4 for a list of payments due on total long-term debt and capitalized lease requirements.
     Upon adoption of FIN 48, we are now required to include uncertain tax positions in our contractual obligation disclosure. We have uncertain tax positions of approximately $186 million and we expect to pay these in 2007. See Note 8.
      Off-Balance Sheet Arrangements
     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.
     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2007, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 million.
 46 

Table of Contents

      Guarantees and Letters of Credit
     We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to these obligations. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 15 for additional information regarding guarantees and letters of credit.
      Credit Ratings
     The ratings of securities of Pinnacle West and APS as of May 8, 2007 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase the cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).
 	 	 	 	 	 	 	
 	 	Moody’s	 	Standard & Poor’s	 	Fitch	
Pinnacle West	 	 	 	 	 	 	
Senior unsecured (a)	 	Baa3 (P)	 	BB+ (prelim)	 	N/A	
Commercial paper	 	P-3	 	A-3	 	F-3	
Outlook	 	Negative	 	Stable	 	Stable	
 	 	 	 	 	 	 	
APS	 	 	 	 	 	 	
Senior unsecured	 	Baa2	 	BBB-	 	BBB	
Secured lease obligation bonds	 	Baa2	 	BBB-	 	BBB-	
Commercial paper	 	P-2	 	A-3	 	F-2	
Outlook	 	Negative	 	Stable	 	Stable	

(a)	 	Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigns a provisional (P) rating and Standard & Poor’s assigns a preliminary (prelim) rating to the senior unsecured securities under such shelf registrations.	
      Debt Provisions
     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At March 31, 2007, the ratio was approximately 49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was
 47 

Table of Contents

approximately 4.7 times under APS’ bank financing agreements as of March 31, 2007. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.
     Neither Pinnacle West’s nor APS’ financing agreements contain “rating triggers” that would result in an acceleration of the required interest and principal payments in the event of a rating downgrade. However, in the event of a rating downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.
     All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.
     See Note 4 for further discussions.
Capital Needs and Resources — By Company
      Pinnacle West (Parent Company)
     Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common stock dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.
     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At March 31, 2007, APS’ common equity ratio, as defined, was approximately 53%.
     Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $47 million in 2006. The contribution to our pension plan in 2007 is estimated to be approximately $22 million, and the contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $21 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.
 48 

Table of Contents

      APS
     APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.
     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On December 15, 2006, APS filed a financing application with the ACC requesting an increase in APS’ current short-term and long-term debt authorizations. In the financing application, APS requested an increase to its current short-term debt authorization (7% of APS’capitalization) to 7% of APS’capitalization plus $500 million in order to meet its growing working capital needs. In addition, APS requested an increase to its current long-term debt authorization (approximately $3.2 billion) to approximately $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected future financing needed to fund APS’ capital expenditure and maintenance program and other cash requirements.
     See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” in Note 5 for information regarding the PSA approved by the ACC. Although APS defers actual retail fuel and purchased power costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.
     See “Cash Flow Hedges” in Note 10 for information related to collateral provided to us by counterparties.
      Other Subsidiaries
     During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during the three months ended March 31, 2007 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.
     El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.
     APS Energy Services expects minimal capital expenditures over the next three years.
     See “Overview” above and Note 4 for discussion of Pinnacle West Marketing & Trading, the Company’s newly-formed marketing and trading subsidiary.
CRITICAL ACCOUNTING POLICIES
     In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,
 49 

Table of Contents

expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting, the determination of the appropriate accounting for our pension and other postretirement benefits and derivatives accounting. There have been no changes to our critical accounting policies since our 2006 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2006 Form 10-K for further details about our critical accounting policies.
OTHER ACCOUNTING MATTERS
     In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance.
     In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance.
     See Note 8 for a discussion of FASB Interpretation No. 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial.
PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK
Factors Affecting Operating Revenues, Fuel and Purchased Power Costs
      General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. For the years 2004 through 2006, retail electric revenues comprised approximately 82% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer mix, customer growth, average usage per customer, electricity rates and tariffs, variations in weather from period to period, and amortization of PSA deferrals. Competitive retail sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition. Off-System Sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because the gross margin is credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including demand and prices. Competitive wholesale transactions are made by the marketing and trading group through structured trading opportunities involving matched sales and purchases of commodities.
      Retail Rate Proceedings The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC, which are discussed in greater detail in Note 5. The most significant pending retail rate proceedings are APS’ general rate case request and an application for a 1.9% PSA surcharge, or temporary rate
 50 

Table of Contents

increase, related to incremental replacement power costs incurred by APS in 2005 in connection with unplanned outages at Palo Verde, which is subject to the ACC’s review of the unplanned outages. These matters have been consolidated procedurally and a decision on them by the ACC is expected in the second quarter of 2007. In addition, the ACC staff is conducting a review of the prudence of approximately $79 million in PSA deferrals related to 2006 unplanned outages at Palo Verde.
      Fuel and Purchased Power Costs Fuel and purchased power costs included on our income statements are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the amortization thereof. See “Power Supply Adjustor” in Note 5 for information regarding the PSA, including PSA deferrals related to Palo Verde unplanned outages and reduced power operations that are the subject of ACC prudence reviews. APS’ recovery of PSA deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.
      Customer and Sales Growth The customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory for the three-month period ended March 31, 2007 was 3.8% compared with the prior-year period. Such growth averaged 4.1% a year for the three years from 2004 through 2006; and we currently expect customer growth to average about 4.0% per year from 2007 to 2009. For the three years 2004 through 2006, APS’ actual retail electricity sales in kilowatt-hours grew at an average rate of 4.2%; adjusted to exclude effects of weather variations, such retail sales growth averaged 4.6% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.2% on average, from 2007 through 2009, before the effects of weather variations. We currently expect our retail sales growth in 2007 to be below average because of potential effects on customer usage from the retail rate increases proposed by APS (see Note 5).
     Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth, usage patterns and responses to retail price changes. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.
      Weather In forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.
      Wholesale Market Conditions Our marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity, fuels and emission allowances and credits.
 51 

Table of Contents

Other Factors Affecting Financial Results
      Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher-trending pension and other postretirement benefit costs and other factors.
      Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction, changes in depreciation and amortization rates, and changes in regulatory asset amortization.
      Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessed valuation ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to increase as new power plants (including the Sundance Plant acquired in 2005) and additions to our transmission and distribution facilities are included in the property tax base.
      Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.
      Retail Competition Although some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.
      Subsidiaries SunCor’s net income was $61 million in 2006, $56 million in 2005, and $45 million in 2004. See Note 17 for further discussion. We currently expect SunCor’s net income in 2007 will be between $30 million and $35 million. This estimate reflects a slow-down in the western United States residential real estate markets.
     APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.
      General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.
Market Risks
     Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.
      Interest Rate and Equity Risk
     We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear
 52 

Table of Contents

decommissioning trust fund. The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.
      Commodity Price Risk
     We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.
     The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories:

 	•	 	Regulated Electricity – non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and	
 		
 	•	 	Marketing and Trading – non-trading and trading derivative instruments of our competitive business activities.	
     The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions for the three months ended March 31, 2007 and 2006 (dollars in millions):
 53 

Table of Contents

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three Months Ended	 	 	Three Months Ended	 	
 	 	March 31, 2007	 	 	March 31, 2006	 	
 	 	Regulated	 	 	Marketing	 	 	Regulated	 	 	Marketing	 	
 	 	Electricity	 	 	and Trading	 	 	Electricity	 	 	and Trading	 	
Mark-to-market of net positions at beginning of period	 	$	(62	)	 	$	77	 	 	$	335	 	 	$	181	 	
Recognized in earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in mark-to-market gains (losses) for future period deliveries	 	 	5	 	 	 	6	 	 	 	(5	)	 	 	—	 	
Mark-to-market gains realized including ineffectiveness during the period	 	 	(2	)	 	 	(4	)	 	 	(4	)	 	 	(1	)	
Deferred as a regulatory liability (asset)	 	 	53	 	 	 	—	 	 	 	(49	)	 	 	—	 	
Recognized in OCI:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Change in mark-to-market for future period deliveries – gains (losses) (a)	 	 	51	 	 	 	12	 	 	 	(163	)	 	 	(42	)	
Mark-to-market (gains) losses realized during the period	 	 	1	 	 	 	(6	)	 	 	(10	)	 	 	(7	)	
Change in valuation techniques	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market of net positions at end of period	 	$	46	 	 	$	85	 	 	$	104	 	 	$	131	 	

			
(a)	 	The increases (decreases) in regulated mark-to-market recorded in OCI are due primarily to increases (decreases) in forward natural gas prices.	
     The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at March 31, 2007 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2006 Form 10-K for more discussion of our valuation methods.
Regulated Electricity
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Years	 	 	Total fair	 	
Source of Fair Value	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	2011	 	 	thereafter	 	 	value	 	
Prices actively quoted	 	$	26	 	 	$	22	 	 	$	2	 	 	$	3	 	 	$	—	 	 	$	—	 	 	$	53	 	
Prices provided by other external sources	 	 	12	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	12	 	
Prices based on models and other valuation methods	 	 	(3	)	 	 	(2	)	 	 	(1	)	 	 	(4	)	 	 	(2	)	 	 	(7	)	 	 	(19	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total by maturity	 	$	35	 	 	$	20	 	 	$	1	 	 	$	(1	)	 	$	(2	)	 	$	(7	)	 	$	46	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 54 

Table of Contents

Marketing and Trading
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	Years	 	 	Total fair	 	
Source of Fair Value	 	2007	 	 	2008	 	 	2009	 	 	2010	 	 	2011	 	 	thereafter	 	 	value	 	
Prices actively quoted	 	$	15	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	15	 	
Prices provided by other external sources	 	 	37	 	 	 	21	 	 	 	—	 	 	 	—	 	 	 	2	 	 	 	2	 	 	 	62	 	
Prices based on models and other valuation methods	 	 	(6	)	 	 	18	 	 	 	(1	)	 	 	(1	)	 	 	(1	)	 	 	(1	)	 	 	8	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total by maturity	 	$	46	 	 	$	39	 	 	$	(1	)	 	$	(1	)	 	$	1	 	 	$	1	 	 	$	85	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
     The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2007 and December 31, 2006 (dollars in millions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	March 31, 2007	 	 	December 31, 2006	 	
 	 	Gain (Loss)	 	 	Gain (Loss)	 	
 	 	Price Up	 	 	Price	 	 	Price Up	 	 	Price	 	
 	 	10%	 	 	Down 10%	 	 	10%	 	 	Down 10%	 	
Commodity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Mark-to-market changes reported in OCI (a):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Electricity	 	$	40	 	 	$	(40	)	 	$	38	 	 	$	(38	)	
Natural gas	 	 	88	 	 	 	(88	)	 	 	80	 	 	 	(80	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Total	 	$	128	 	 	$	(128	)	 	$	118	 	 	$	(118	)	

			
(a)	 	These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.	
Credit Risk
     We are exposed to losses in the event of non-performance or non-payment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 11% of Pinnacle West’s risk management and trading assets as of March 31, 2007. See Note 1, “Derivative Accounting” in Item 8 of our 2006 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.
ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS
General
     Throughout the following explanations of our results of operations, we refer to “gross margin.” Gross margin refers to electric operating revenues less fuel and purchased power costs. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.2 reconciles this non-GAAP financial measure to operating income, which is the most directly
 55 

Table of Contents

comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses.
Deferred Fuel and Purchased Power Costs
     APS settled its 2003 general retail rate case effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications. (See “Power Supply Adjustor” in Note 5.)
     Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates, primarily due to the use of higher cost resources and higher fuel prices, and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA accumulated unrecovered deferrals at March 31, 2007 was approximately $118 million. The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power.
     APS recorded PSA deferrals of (a) $45 million related to replacement power costs in 2005 associated with unplanned Palo Verde outages and (b) $79 million related to replacement power costs in 2006 associated with unplanned outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages and reduced power operations are the subject of ACC prudence reviews. The ACC staff has completed its prudence review of 2005 unplanned outages and has recommended disallowance of $16 million of the 2005 costs. The recommendation is being considered as part of APS’ general rate case currently pending before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 5. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the deferrals related to the unplanned 2005 Palo Verde outages. See “ALJ Recommended Order” in Note 5. Neither the ACC staff recommendation nor the ALJ recommendation changes management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable. The prudence review of 2006 unplanned outages has not yet been completed.
Operating Results – Three-month period ended March 31, 2007 compared with three-month period ended March 31, 2006
     APS’ net income for the three months ended March 31, 2007 was $4 million compared with a net loss $6 million for the comparable prior-year period. The $10 million increase was primarily due to the effects of cooler weather on retail sales; higher retail sales due to customer growth; and lower operations and maintenance expense related to generation. In addition, higher fuel and purchased power costs were partially offset by the deferral of such costs in accordance with the PSA. See “Deferred Fuel and Purchased Power Costs” above.
 56 

Table of Contents

`
     Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):
 	 	 	 	 	 	 	 	 	
 	 	Increase (Decrease)	 	
 	 	Pretax	 	 	After Tax	 	
Gross margin:	 	 	 	 	 	 	 	 	
Effects of cooler weather on retail sales	 	$	13	 	 	$	8	 	
Higher retail sales due to customer growth, excluding weather effects	 	 	10	 	 	 	6	 	
Higher fuel and purchased power costs due to increased prices (see “Deferred Fuel and Purchased Power Costs” above)	 	 	(14	)	 	 	(9	)	
Increased deferred fuel and purchased power costs	 	 	12	 	 	 	7	 	
Lower gains on marketing and trading	 	 	(9	)	 	 	(5	)	
Miscellaneous items, net	 	 	3	 	 	 	3	 	
 	 	 	 	 	 	 	
Net increase in gross margin	 	 	15	 	 	 	10	 	
Operations and maintenance decreases primarily due to:	 	 	 	 	 	 	 	 	
Generation costs, including fewer power plant maintenance outages	 	 	4	 	 	 	2	 	
Miscellaneous items, net	 	 	3	 	 	 	2	 	
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates	 	 	(5	)	 	 	(3	)	
Miscellaneous items, net	 	 	(2	)	 	 	(1	)	
 	 	 	 	 	 	 	
Net increase in net income	 	$	15	 	 	$	10	 	
 	 	 	 	 	 	 	
Regulated Electricity Revenues
     Regulated electricity revenues were $70 million higher for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

 	•	 	a $51 million increase in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);	
 		
 	•	 	an $18 million increase in retail revenues due to cooler weather;	
 		
 	•	 	a $13 million increase in retail revenues related to customer growth, excluding weather effects;	
 		
 	•	 	a $5 million decrease in Off-System Sales due to lower sales volumes; and	
 		
 	•	 	a $7 million decrease due to miscellaneous factors.	
Marketing and Trading Revenues
     Marketing and trading revenues were $9 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of a decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices.
 57 

Table of Contents

ARIZONA PUBLIC SERVICE COMPANY – LIQUIDITY AND CAPITAL RESOURCES
      Contractual Obligations
     APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.5 billion at December 31, 2006 to $2.7 billion at March 31, 2007 as follows (dollars in billions):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
2007	 	2008-2009	 	2010-2011	 	Thereafter	 	Total	
$0.5	 	$	0.5	 	 	$	0.4	 	 	$	1.3	 	 	$	2.7	 	
     See Note 4 for a list of APS’ payments due on total long-term debt and capitalized lease requirements.
     Upon adoption of FIN 48, APS is now required to include uncertain tax positions in the contractual obligations disclosure. APS has uncertain tax positions of approximately $179 million and expects to pay these in 2007. See Note 8.
FORWARD-LOOKING STATEMENTS
     This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “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 results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2006 Form 10-K, these factors include, but are not limited to:

 	•	 	state and federal regulatory and legislative decisions and actions, including the outcome and timing of APS’ retail rate proceedings pending before the ACC;	
 		
 	•	 	the timely recovery of PSA deferrals, including such deferrals in 2005 and 2006 associated with unplanned Palo Verde outages and reduced power operations that are the subject of ACC prudence reviews;	
 		
 	•	 	the ongoing restructuring of the electric industry, including the introduction of retail electric competition in Arizona and decisions impacting wholesale competition;	
 		
 	•	 	the outcome of regulatory, legislative and judicial proceedings, both current and future, relating to the restructuring;	
 		
 	•	 	market prices for electricity and natural gas;	
 		
 	•	 	power plant performance and outages;	
 		
 	•	 	transmission outages and constraints;	
 		
 	•	 	weather variations affecting local and regional customer energy usage;	
 		
 	•	 	customer growth and energy usage;	
 		
 	•	 	regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile fuel and purchased power costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies;	
 		
 	•	 	the cost of debt and equity capital and access to capital markets;	
 58 

Table of Contents

 	•	 	current credit ratings remaining in effect for any given period of time;	
 		
 	•	 	our ability to compete successfully outside traditional regulated markets (including the wholesale market);	
 		
 	•	 	the performance of our marketing and trading activities due to volatile market liquidity and any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);	
 		
 	•	 	changes in accounting principles generally accepted in the United States of America and the interpretation of those principles;	
 		
 	•	 	the performance of the stock market and the changing interest rate environment, which affect the value of our nuclear decommissioning trust, pension, and other postretirement benefit plan assets, the amount of required contributions to Pinnacle West’s pension plan and contributions to APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits;	
 		
 	•	 	technological developments in the electric industry;	
 		
 	•	 	the strength of the real estate market in SunCor’s market areas, which include Arizona, Idaho, New Mexico and Utah; and	
 		
 	•	 	other uncertainties, all of which are difficult to predict and many of which are beyond the control of Pinnacle West and APS.	
 59 

Table of Contents

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.
Item 4. CONTROLS AND PROCEDURES
     (a) Disclosure Controls and Procedures
     The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq .) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.
     Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2007. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.
     APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of March 31, 2007. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.
     (b) Changes In Internal Control Over Financial Reporting
     The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
     No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended March 31, 2007 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.
 60 

Table of Contents
Part II — OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
     See Note 12 in regard to pending or threatened litigation or other disputes.
Item 1A. RISK FACTORS
     In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in the 2006 Form 10-K, which could materially affect the business, financial condition or future results of APS and Pinnacle West. The risks described in the 2006 Form 10-K are not the only risks facing APS and Pinnacle West. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition and/or operating results of APS and Pinnacle West.
Item 5. OTHER INFORMATION
Construction and Financing Programs
     See “Liquidity and Capital Resources” in Part I, Item 2 of this report for a discussion of construction and financing programs of the Company and its subsidiaries.
Regulatory Matters
     See Note 5 for a discussion of regulatory developments.
Environmental Matters
     See “Environmental Matters – Superfund” in Note 12 for a discussion of a Superfund site.
      Federal Implementation Plan (“FIP”)
     In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and the Four Corners Power Plant. On July 26, 2006, the Sierra Club sued the EPA in an attempt to force the EPA to issue a final FIP to limit emissions at the Four Corners Power Plant. On September 12, 2006, the EPA proposed a revised FIP to establish air quality standards at Four Corners and the Navajo Generating Station. On September 18, 2006, APS filed a motion to intervene in the Sierra Club’s lawsuit against the EPA, in order to assure that its interests are protected. On November 22, 2006, the court granted APS’ motion to intervene in the lawsuit. In December 2006, the court issued a consent decree signed by the Sierra Club and the EPA; the consent decree requires EPA to take “final action” on the proposed FIP by April 30, 2007. On April 30, 2007, the EPA issued the final FIP for Four Corners. The FIP essentially federalizes the requirements contained in the New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also includes a requirement to control fugitive dust within 18 months after the FIP becomes effective. (Fugitive dust is dust that is blown within the vicinity of the plant as a result of human activity, the wind, or both.) We do not believe the Four Corners FIP will have a material impact on our financial position, results of operations, cash flows or liquidity. The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently predict the effect of this proposed FIP on the Company’s financial position, results of operations, cash flows or liquidity, or whether the proposed FIP will be adopted in its current form.
 61 

Table of Contents

      Regional Haze Rules
     On April 22, 1999, the EPA announced final regional haze rules. These regulations require states to submit state implementation plans (SIPs) by December 2007 to demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class I Areas,” including several on the Colorado Plateau. The SIP is required to consider and potentially apply “best available retrofit technology” (BART) for certain older major stationary sources. The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.
     On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional haze rules by providing guidelines, known as the BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. The EPA also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court remand of that rule.
     The Arizona Department of Environmental Quality (ADEQ) is currently undertaking a rulemaking process to amend its SIP to reconcile it with the Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. As part of the rulemaking process, the ADEQ will require certain sources in the state to conduct BART analyses, potentially including Cholla and other APS plants. The ADEQ’s Regional Haze SIPs are due to EPA Region 9 in December 2007. In addition, we anticipate that EPA Region 9 may require Four Corners to conduct a BART analysis. The Company cannot currently predict the outcome of these proceedings.
      Greenhouse Gas Accord
     On February 26, 2007 five western states (Arizona, California, New Mexico, Oregon and Washington) entered into an accord to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. The agreement requires the states to set emission goals within six months and determine a specific plan to meet such goals within eighteen months. While we continue to monitor the impact of this accord, we cannot predict its impact on our operations at this time.
      Hazardous Air Pollutants Rule
     ADEQ promulgated a Hazardous Air Pollutants (HAPs) rule that became effective on January 1, 2007. The HAPs rule requires certain sources of HAPs to evaluate and potentially apply pollution control technologies to limit HAPs emissions, or demonstrate through a risk management analysis that controls are not warranted. The rule is being challenged for its validity and currently does not apply in the counties in which APS has power plants. The APS plants potentially subject to HAPs regulation are the Saguaro Power Plant, located in Pinal County, and the Ocotillo and West Phoenix Power Plants, located in Maricopa County. State law requires these counties to adopt their own versions of the rule, and Maricopa County already is in the process of doing so. APS is monitoring the HAPs rule, its impact in the relevant counties and its validity. APS does not expect this matter to have a material adverse effect on its financial statements, results of operations, cash flows or liquidity.
 62 

Table of Contents
Item 6. EXHIBITS
     (a) Exhibits
 	 	 	 	 	
Exhibit No.	 	Registrant(s)	 	Description	
10.1	 	Pinnacle West
APS	 	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1, 2007	
 	 	 	 	 	
10.2	 	Pinnacle West
APS	 	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1, 2007	
 	 	 	 	 	
12.1	 	Pinnacle West	 	Ratio of Earnings to Fixed Charges	
 	 	 	 	 	
12.2	 	APS	 	Ratio of Earnings to Fixed Charges	
 	 	 	 	 	
12.3	 	Pinnacle West	 	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements	
 	 	 	 	 	
31.1	 	Pinnacle West	 	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	
 	 	 	 	 	
31.2	 	Pinnacle West	 	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	
 	 	 	 	 	
31.3	 	APS	 	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	
 	 	 	 	 	
31.4	 	APS	 	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended	
 	 	 	 	 	
32.1	 	Pinnacle West	 	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	
 63 

Table of Contents

 	 	 	 	 	
Exhibit No.	 	Registrant(s)	 	Description	
32.2	 	APS	 	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	
 	 	 	 	 	
99.1	 	Pinnacle West	 	Reconciliation of Operating Income to Gross Margin	
 	 	 	 	 	
99.2	 	APS	 	Reconciliation of Operating Income to Gross Margin	
     In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:
 	 	 	 	 	 	 	 	 	
Exhibit	 	 	 	 	 	 	 	Date	
No.	 	Registrant(s)	 	Description	 	Previously Filed as Exhibit a	 	Filed	
3.1	 	Pinnacle West	 	Articles of Incorporation, restated as of July 29, 1988	 	19.1 to Pinnacle West’s September 1988 Form 10-Q Report, File No. 1-8962	 	11-14-88	
 	 	 	 	 	 	 	 	 	
3.2	 	Pinnacle West	 	Pinnacle West Capital Corporation Bylaws, amended as of December 14, 2005	 	3.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	 	12-15-05	
 	 	 	 	 	 	 	 	 	
3.3	 	APS	 	Articles of Incorporation, restated as of May 25, 1988	 	4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	 	9-29-93	
 	 	 	 	 	 	 	 	 	
3.4	 	APS	 	Arizona Public Service Company Bylaws, amended as of June 23, 2004	 	3.1 to APS’ June 30, 2004 Form 10-Q Report, File No. 1-4473	 	8-9-04	

a	 	Reports filed under File Nos. 1-4473 and 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.	
 64 

Table of Contents
SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 	 	 	 	 	
 	PINNACLE WEST CAPITAL CORPORATION
(Registrant)
 	 	
Dated: May 9, 2007 	By:  	/s/ Donald E. Brandt  	 	
 	 	Donald E. Brandt  	 	
 	 	Executive Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report) 	 	
 	
 	ARIZONA PUBLIC SERVICE COMPANY
(Registrant)
 	 	
Dated: May 9, 2007 	By:  	/s/ Donald E. Brandt  	 	
 	 	Donald E. Brandt  	 	
 	 	President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report) 	 	
 	
 65 

Exhibit 10.1
AMENDMENT NO. 5
Decommissioning Trust Agreement
(PVNGS Unit l)
          This Amendment No. 5 dated as of May 1, 2007, to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of July 1, 1991, as amended by Amendment No. 1 thereto dated as of December 1, 1994, Amendment No. 2 thereto dated as of December 16, 1996, Amendment No. 3 thereto dated as of March 18, 2002, and Amendment No. 4 thereto dated as of December 19, 2003 (the “Decommissioning Trust Agreement”, terms used herein as therein defined), is entered into between Arizona Public Service Company (“APS”) and Mellon Bank, N.A., as Decommissioning Trustee (“Decommissioning Trustee”).
R E C I T A L S :
          WHEREAS, the parties hereto wish to amend the Decommissioning Trust Agreement.
          NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
          SECTION 1. Amendment.

 	(a)	 	Paragraph (c) of Section 5 shall be restated as follows:	
 		
 	 	 	to (i) hold assets, in a depository, in a clearing corporation, in book entry form, or by any subcustodian or other entity or in any other manner permitted by law; provided that the Decommissioning Trustee shall not be responsible for any losses resulting from the deposit or maintenance of securities or other property (in accordance with market practice, custom, or regulation) with any foreign or domestic clearing facility, book-entry system, centralized custodial depository, or similar organization generally used by professional custodians engaged in the banking or trust company industry within the applicable market for the asset type in question, and (ii) settle transactions in futures and/or options contracts, short-selling programs, foreign exchange or foreign exchange contracts, swaps and other derivative investments with third parties;	
 		
 	(b)	 	Paragraph (a) of Section 8 shall be restated as follows:	
 		
 	 	 	To hold, manage, invest, and reinvest the assets of the Funds; provided however that notwithstanding the provisions of Section 8(c), Decommissioning Trustee shall, at the close of business on each day, without prior approval or direction from the Investment Manager(s), have the power, rights, and responsibility to invest cash balances, including those held as part of an account of the Investment Manager(s), as authorized in writing delivered to the Decommissioning Trustee by APS. Nothing in this Section shall be construed as authorizing	

 

 	 	 	Decommissioning Trustee to carry on any business or to divide the gains therefrom.	
 		
 	(c)	 	The first sentence of clause (ii) of Paragraph (c) of Section 8 shall be deleted.	
 		
 	(d)	 	The third sentence of clause (ii) of Paragraph (c) of Section 8 shall be restated as follows:	
 		
 	 	 	Upon proper notification from the Investment Manager(s), Decommissioning Trustee shall execute and deliver instruments in accordance with the appropriate trading authorizations; provided that the Decommissioning Trustee shall not follow any direction that would result in assets of the Second Fund being invested in investments not allowed for a qualified nuclear decommissioning reserve fund under Section 468A of the Code and the regulations thereunder.	
 		
 	(e)	 	Clause (ii) of Paragraph (d) of Section 8 shall be restated as follows:	
 		
 	 	 	Decommissioning Trustee is required to supervise and review the securities and other assets and investments authorized for purchase by the Investment Managers(s) within two weeks of the end of the calendar month during which such purchase was made to determine that such securities, assets and/or investments are in accordance with the notice communicated in writing to and accepted by the Decommissioning Trustee, whose acceptance shall not be unreasonably withheld. Upon the completion of such review, the Decommissioning Trustee shall promptly notify APS in writing if any securities, assets or investments are not consistent with such notice.	
 		
 	(f)	 	Section 11 shall be restated as follows:	
 		
 	 	 	Limitations on Transfer and Assignment. APS may not, in whole or in part, transfer, assign, pledge, encumber, or grant any security interest in its beneficial interest under this Agreement or in either of the Funds, whether voluntary or involuntary, except for (i) Permitted Liens, and (ii) as otherwise required or allowed by Applicable Law.	
 		
 	 	 	Notwithstanding the foregoing, if the Decommissioning Trustee advances cash or securities for any purpose or in the event that the Decommissioning Trustee shall incur or be assessed taxes, interest, charges, expenses, assessments, or other liabilities in connection with the performance of this Agreement, except such as may arise from its failure to exercise due care, any property at any time held for the Fund or under this Agreement shall be security therefor and the Decommissioning Trustee shall be entitled to collect from the Fund sufficient cash for reimbursement, and if such cash is insufficient, dispose of the assets held under this Agreement to the extent necessary to obtain reimbursement.	
 2 

 

 	 	 	Nothwithstanding the foregoing, nothing in this Agreement shall prohibit the lending of the assets of the Fund in accordance with the terms and conditions of a separate securities lending agreement.	
 		
 	(g)	 	The second sentence of the fourth paragraph of Section 21 shall be restated as follows:	
 		
 	 	 	Decommissioning Trustee shall promptly advise APS if it has actual knowledge that any of the investments are not in accordance with the notice communicated in writing to and accepted by the Decommissioning Trustee.	
 		
 	(h)	 	The following shall be added to the first paragraph of Section 23.	
 		
 	 	 	The Decommissioning Trustee shall not be responsible or liable for any losses or damages suffered by the Fund arising as a result of the insolvency of any custodian, (other than the Decommissioning Trustee or any affiliate of the Decommissioning Trustee) subtrustee or subcustodian, except to the extent the Decommissioning Trustee failed to exercise due care in its selection, monitoring or continued retention of such entity. Settlements of transactions may be effected in trading and processing practices customary in the jurisdiction or market where the transaction occurs. APS acknowledges that this may, in certain circumstances, require the delivery of cash or securities (or other property) without the concurrent receipt of securities (or other property) or cash. In such circumstances, provided the Trustee has exercised due care and used reasonable efforts, the Decommissioning Trustee shall have no responsibility for nonreceipt of payment (or late payment) or nondelivery of securities or other property (or late delivery) by the counterparty.	
 		
 	(i)	 	The definition of the term “Permitted Investments” in Exhibit A to the Decommissioning Trust Agreement is hereby deleted.	
 		
 	(j)	 	Exhibit B to the Decommissioning Trust Agreement is hereby deleted.	
           SECTION 2. Miscellaneous

 	(a)	 	Full Force and Effect.	
          Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to “this Agreement,” “hereto,” “hereof” and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby.

 	(b)	 	Counterparts/Representations.	
 3 

 

          The Amendment No. 5 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 5 by signing any such counterpart. Each party represents and warrants to the other that it has full authority to enter into this Amendment upon the terms and conditions hereof and that the individual executing this Amendment on its behalf has the requisite authority to bind that Party.
          IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 5 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
 	 	 	 	 	 	 	
 	 	ARIZONA PUBLIC SERVICE COMPANY	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Janice Emery
 	 	 	
 	 	Title:	 	Director, Trust Investments	 	 	

 	 	MELLON BANK, N.A. as Decommissioning Trustee	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Thomas J. McNally	 	 	
 	 	 	 	 	 	 	
 	 	Title:	 	Vice President	 	 	
 	 	 	 	 	 	 	
 4 

 

 	 	 	 	 	
STATE OF ARIZONA	) 	 		 	
 	) ss: 		
County of Maricopa	) 	 		 	
     The foregoing instrument was acknowledged before me this 16 th day of April, 2007, by Janice Emery, the Director Trust Invest of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
 	 	 	 	 	
 	 	/s/ Suzanne Wineck
 
Notary Public	 	 	

COMMONWEALTH OF PENNSYLVANIA	) 	 		 	
 	) ss: 		
County of Allegheny	) 	 		 	
     The foregoing instrument was acknowledged before me this 26 th day of April, 2007, by Thomas J. McNally, a Vice President of Mellon Bank, N.A. a national banking association having trust powers, as Decommissioning Trustee, on behalf of said national banking association.
 	 	 	 	 	
 	 	/s/ Julie Ann Mosco
 
Notary Public	 	 	
 	 	 	 	 	
 	 	COMMONWEALTH OF PENNSYLVANIA	 	 	
 	 	Notarial Seal
Julie Ann Mosco, Notary Public
City Of Pittsburgh, Allegheny County
My Commission Expires Oct. 13, 2007	 	 	
 	 	 	 	 	
 	 	Member, Pennsylvania Association Of Notaries	 	 	
My commission expires:
October 13, 2007
 5 

Exhibit 10.2
AMENDMENT NO. 5
Decommissioning Trust Agreement
(PVNGS Unit 3)
          This Amendment No. 5 dated as of May 1, 2007, to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of July 1, 1991, as amended by Amendment No. 1 thereto dated as of December 1, 1994, Amendment No. 2 thereto dated as of December 16, 1996, Amendment No. 3 thereto dated as of March 18, 2002, and Amendment No. 4 thereto dated as of December 19, 2003 (the “Decommissioning Trust Agreement”, terms used herein as therein defined), is entered into between Arizona Public Service Company (“APS”) and Mellon Bank, N.A., as Decommissioning Trustee (“Decommissioning Trustee”).
R E C I T A L S:
          WHEREAS, the parties hereto wish to amend the Decommissioning Trust Agreement.
          NOW, THEREFORE, in consideration of the premises and of other good and valuable consideration, receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:
          SECTION 1. Amendment.

 	(a)	 	Paragraph (c) of Section 5 shall be restated as follows:	
 		
 	 	 	to (i) hold assets, in a depository, in a clearing corporation, in book entry form, or by any subcustodian or other entity or in any other manner permitted by law; provided that the Decommissioning Trustee shall not be responsible for any losses resulting from the deposit or maintenance of securities or other property (in accordance with market practice, custom, or regulation) with any foreign or domestic clearing facility, book-entry system, centralized custodial depository, or similar organization generally used by professional custodians engaged in the banking or trust company industry within the applicable market for the asset type in question, and (ii) settle transactions in futures and/or options contracts, short-selling programs, foreign exchange or foreign exchange contracts, swaps and other derivative investments with third parties;	
 		
 	(b)	 	Paragraph (a) of Section 8 shall be restated as follows:	
 		
 	 	 	To hold, manage, invest, and reinvest the assets of the Funds; provided however that notwithstanding the provisions of Section 8(c), Decommissioning Trustee shall, at the close of business on each day, without prior approval or direction from the Investment Manager(s), have the power, rights, and responsibility to invest cash balances, including those held as part of an account of the Investment Manager(s), as authorized in writing delivered to the Decommissioning Trustee by APS. Nothing in this Section shall be construed as authorizing	

 

 	 	 	Decommissioning Trustee to carry on any business or to divide the gains therefrom.	
 		
 	(c)	 	The first sentence of clause (ii) of Paragraph (c) of Section 8 shall be deleted.	
 		
 	(d)	 	The third sentence of clause (ii) of Paragraph (c) of Section 8 shall be restated as follows:	
 		
 	 	 	Upon proper notification from the Investment Manager(s), Decommissioning Trustee shall execute and deliver instruments in accordance with the appropriate trading authorizations; provided that the Decommissioning Trustee shall not follow any direction that would result in assets of the Second Fund being invested in investments not allowed for a qualified nuclear decommissioning reserve fund under Section 468A of the Code and the regulations thereunder.	
 		
 	(e)	 	Clause (ii) of Paragraph (d) of Section 8 shall be restated as follows:	
 		
 	 	 	Decommissioning Trustee is required to supervise and review the securities and other assets and investments authorized for purchase by the Investment Managers(s) within two weeks of the end of the calendar month during which such purchase was made to determine that such securities, assets and/or investments are in accordance with the notice communicated in writing to and accepted by the Decommissioning Trustee, whose acceptance shall not be unreasonably withheld. Upon the completion of such review, the Decommissioning Trustee shall promptly notify APS in writing if any securities, assets or investments are not consistent with such notice.	
 		
 	(f)	 	Section 11 shall be restated as follows:	
 		
 	 	 	Limitations on Transfer and Assignment. APS may not, in whole or in part, transfer, assign, pledge, encumber, or grant any security interest in its beneficial interest under this Agreement or in either of the Funds, whether voluntary or involuntary, except for (i) Permitted Liens, and (ii) as otherwise required or allowed by Applicable Law.	
 		
 	 	 	Notwithstanding the foregoing, if the Decommissioning Trustee advances cash or securities for any purpose or in the event that the Decommissioning Trustee shall incur or be assessed taxes, interest, charges, expenses, assessments, or other liabilities in connection with the performance of this Agreement, except such as may arise from its failure to exercise due care, any property at any time held for the Fund or under this Agreement shall be security therefor and the Decommissioning Trustee shall be entitled to collect from the Fund sufficient cash for reimbursement, and if such cash is insufficient, dispose of the assets held under this Agreement to the extent necessary to obtain reimbursement.	
 2 

 

 	 	 	Nothwithstanding the foregoing, nothing in this Agreement shall prohibit the lending of the assets of the Fund in accordance with the terms and conditions of a separate securities lending agreement.	
 		
 	(g)	 	The second sentence of the fourth paragraph of Section 21 shall be restated as follows:	
 		
 	 	 	Decommissioning Trustee shall promptly advise APS if it has actual knowledge that any of the investments are not in accordance with the notice communicated in writing to and accepted by the Decommissioning Trustee.	
 		
 	(h)	 	The following shall be added to the first paragraph of Section 23.	
 		
 	 	 	The Decommissioning Trustee shall not be responsible or liable for any losses or damages suffered by the Fund arising as a result of the insolvency of any custodian, (other than the Decommissioning Trustee or any affiliate of the Decommissioning Trustee) subtrustee or subcustodian, except to the extent the Decommissioning Trustee failed to exercise due care in its selection, monitoring or continued retention of such entity. Settlements of transactions may be effected in trading and processing practices customary in the jurisdiction or market where the transaction occurs. APS acknowledges that this may, in certain circumstances, require the delivery of cash or securities (or other property) without the concurrent receipt of securities (or other property) or cash. In such circumstances, provided the Trustee has exercised due care and used reasonable efforts, the Decommissioning Trustee shall have no responsibility for nonreceipt of payment (or late payment) or nondelivery of securities or other property (or late delivery) by the counterparty.	
 		
 	(i)	 	The definition of the term “Permitted Investments” in Exhibit A to the Decommissioning Trust Agreement is hereby deleted.	
 		
 	(j)	 	Exhibit B to the Decommissioning Trust Agreement is hereby deleted.	
          SECTION 2. Miscellaneous
               (a) Full Force and Effect.
          Except as expressly provided herein, the Decommissioning Trust Agreement shall remain unchanged and in full force and effect. Each reference in the Decommissioning Trust Agreement and in any exhibit or schedule thereto to “this Agreement,” “hereto,” “hereof” and terms of similar import shall be deemed to refer to the Decommissioning Trust Agreement as amended hereby.
               (b) Counterparts/Representations.
 3 

 

     The Amendment No. 5 may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any of the parties hereto may execute this Amendment No. 5 by signing any such counterpart. Each party represents and warrants to the other that it has full authority to enter into this Amendment upon the terms and conditions hereof and that the individual executing this Amendment on its behalf has the requisite authority to bind that Party.
     IN WITNESS WHEREOF, the parties hereto have caused this Amendment No. 5 to the Decommissioning Trust Agreement to be duly executed as of the day and year first above written.
 	 	 	 	 	 	 	
 	 	ARIZONA PUBLIC SERVICE COMPANY	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Janice Emery
 	 	 	
 	 	Title:	 	Director, Trust Investments	 	 	

 	 	MELLON BANK, N.A. as Decommissioning Trustee	 	 	
 	 	 	 	 	 	 	
 	 	By:	 	/s/ Thomas J. McNally	 	 	
 	 	 	 	 	 	 	
 	 	Title:	 	Vice President	 	 	
 	 	 	 	 	 	 	
 4 

 

 	 	 	 	 	
STATE OF ARIZONA	) 	 		 	
 	) ss: 		
County of Maricopa	) 	 		 	
     The foregoing instrument was acknowledged before me this 16 th day of April, 2007, by Janice Emery, the Director Trust Invest of ARIZONA PUBLIC SERVICE COMPANY, an Arizona corporation, on behalf of said corporation.
 	 	 	 	 	
 	 	/s/ Suzanne Wineck
 
Notary Public	 	 	

COMMONWEALTH OF PENNSYLVANIA	) 	 		 	
 	) ss: 		
County of Allegheny	) 	 		 	
     The foregoing instrument was acknowledged before me this 26 th day of April, 2007, by Thomas J. McNally, a Vice President of Mellon Bank, N.A. a national banking association having trust powers, as Decommissioning Trustee, on behalf of said national banking association.
 	 	 	 	 	
 	 	/s/ Julie Ann Mosco
 
Notary Public	 	 	
 	 	 	 	 	
 	 	COMMONWEALTH OF PENNSYLVANIA	 	 	
 	 	Notarial Seal
Julie Ann Mosco, Notary Public
City Of Pittsburgh, Allegheny County
My Commission Expires Oct. 13, 2007	 	 	
 	 	 	 	 	
 	 	Member, Pennsylvania Association Of Notaries	 	 	
My commission expires:
October 13, 2007
 5 

Exhibit 12.1
PINNACLE WEST CAPITAL CORPORATION
COMPUTATION OF EARNINGS TO FIXED CHARGES
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three	 	 	 	 	
 	 	Months	 	 	 	 	
 	 	Ended	 	 	 	 	
 	 	March 31,	 	 	Twelve Months Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	 	2002	 	
Earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	15,798	 	 	$	317,143	 	 	$	223,163	 	 	$	246,590	 	 	$	225,384	 	 	$	236,563	 	
Income taxes	 	 	8,609	 	 	 	156,418	 	 	 	126,892	 	 	 	136,142	 	 	 	102,202	 	 	 	152,145	 	
Fixed charges	 	 	57,799	 	 	 	225,119	 	 	 	214,430	 	 	 	214,803	 	 	 	225,041	 	 	 	219,178	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Earnings	 	$	82,206	 	 	$	698,680	 	 	$	564,485	 	 	$	597,535	 	 	$	552,627	 	 	$	607,886	 	

Fixed Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	$	50,992	 	 	$	196,826	 	 	$	185,087	 	 	$	183,527	 	 	$	193,973	 	 	$	187,039	 	
Estimated interest portion of annual rents	 	 	6,807	 	 	 	28,293	 	 	 	29,343	 	 	 	31,276	 	 	 	31,068	 	 	 	32,139	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Fixed Charges	 	$	57,799	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	

Ratio of Earnings to Fixed	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Charges (rounded down)	 	 	1.42	 	 	 	3.10	 	 	 	2.63	 	 	 	2.78	 	 	 	2.45	 	 	 	2.77	 	

  
 
Exhibit 12.2
ARIZONA PUBLIC SERVICE COMPANY
COMPUTATION OF EARNINGS TO FIXED CHARGES
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three	 	 	 	 	
 	 	Months	 	 	 	 	
 	 	Ended	 	 	 	 	
 	 	March 31,	 	 	Twelve Months Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	 	2002	 	
Earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	4,317	 	 	$	269,730	 	 	$	170,479	 	 	$	199,627	 	 	$	180,937	 	 	$	199,343	 	
Income taxes	 	 	2,389	 	 	 	138,927	 	 	 	98,010	 	 	 	120,030	 	 	 	86,854	 	 	 	126,805	 	
Fixed charges	 	 	49,917	 	 	 	191,174	 	 	 	178,437	 	 	 	181,372	 	 	 	181,793	 	 	 	168,985	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Earnings	 	$	56,623	 	 	$	599,831	 	 	$	446,926	 	 	$	501,029	 	 	$	449,584	 	 	$	495,133	 	

Fixed Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest charges	 	$	42,056	 	 	$	158,769	 	 	$	145,502	 	 	$	146,983	 	 	$	147,610	 	 	$	133,878	 	
Amortization of debt discount	 	 	1,156	 	 	 	4,363	 	 	 	4,085	 	 	 	4,854	 	 	 	3,337	 	 	 	2,888	 	
Estimated interest portion of annual rents	 	 	6,705	 	 	 	28,042	 	 	 	28,850	 	 	 	29,535	 	 	 	30,846	 	 	 	32,219	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Fixed Charges	 	$	49,917	 	 	$	191,174	 	 	$	178,437	 	 	$	181,372	 	 	$	181,793	 	 	$	168,985	 	

Ratio of Earnings to Fixed	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Charges (rounded down)	 	 	1.13	 	 	 	3.13	 	 	 	2.50	 	 	 	2.76	 	 	 	2.47	 	 	 	2.93	 	

  
 
Exhibit 12.3
PINNACLE WEST CAPITAL CORPORATION
COMPUTATION OF EARNINGS TO FIXED CHARGES
AND PREFERRED STOCK DIVIDEND REQUIREMENTS
(dollars in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Three	 	 	 	 	
 	 	Months	 	 	 	 	
 	 	Ended	 	 	 	 	
 	 	March 31,	 	 	Twelve Months Ended December 31,	 	
 	 	2007	 	 	2006	 	 	2005	 	 	2004	 	 	2003	 	 	2002	 	
Earnings:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income from continuing operations	 	$	15,798	 	 	$	317,143	 	 	$	223,163	 	 	$	246,590	 	 	$	225,384	 	 	$	236,563	 	
Income taxes	 	 	8,609	 	 	 	156,418	 	 	 	126,892	 	 	 	136,142	 	 	 	102,202	 	 	 	152,145	 	
Fixed charges	 	 	57,799	 	 	 	225,119	 	 	 	214,430	 	 	 	214,803	 	 	 	225,041	 	 	 	219,178	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Earnings	 	$	82,206	 	 	$	698,680	 	 	$	564,485	 	 	$	597,535	 	 	$	552,627	 	 	$	607,886	 	

Fixed Charges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	$	50,992	 	 	$	196,826	 	 	$	185,087	 	 	$	183,527	 	 	$	193,973	 	 	$	187,039	 	
Estimated interest portion of annual rents	 	 	6,807	 	 	 	28,293	 	 	 	29,343	 	 	 	31,276	 	 	 	31,068	 	 	 	32,139	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Fixed Charges	 	$	57,799	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	

Preferred Stock Dividend	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Requirements:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Income before income taxes	 	$	24,407	 	 	$	473,561	 	 	$	350,055	 	 	$	382,732	 	 	$	327,586	 	 	$	388,708	 	
Net income from continuing operations	 	 	15,798	 	 	 	317,143	 	 	 	223,163	 	 	 	246,590	 	 	 	225,384	 	 	 	236,563	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Ratio of income before income taxes to net income	 	 	1.545	 	 	 	1.493	 	 	 	1.569	 	 	 	1.552	 	 	 	1.453	 	 	 	1.643	 	
Preferred stock dividends	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Preferred Stock Dividend	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Requirements — Ratio (above) Times Preferred Stock Dividends	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	

Fixed Charges and Preferred	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Stock Dividend	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Requirements:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Fixed charges	 	$	57,799	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	
Preferred stock dividend requirements	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Fixed Charges and Preferred Stock Dividend Requirements	 	$	57,799	 	 	$	225,119	 	 	$	214,430	 	 	$	214,803	 	 	$	225,041	 	 	$	219,178	 	

Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements (rounded down)	 	 	1.42	 	 	 	3.10	 	 	 	2.63	 	 	 	2.78	 	 	 	2.45	 	 	 	2.77	 	

  

Exhibit 31.1
CERTIFICATION
I, William J. Post, certify that:

1.	 	I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: May 9, 2007.

 	/s/ William J. Post  	 	
 	William J. Post 	 	
 	Chairman and Chief Executive Officer 	 	
 	
 2 

Exhibit 31.2
CERTIFICATION
I, Donald E. Brandt, certify that:

1.	 	I have reviewed this Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: May 9, 2007.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	Executive Vice President &
Chief Financial Officer 	 	

  

Exhibit 31.3
CERTIFICATION
I, Jack E. Davis, certify that:

1.	 	I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: May 9, 2007.

 	/s/ Jack E. Davis  	 	
 	Jack E. Davis 	 	
 	Chief Executive Officer 	 	
 	
 2 

Exhibit 31.4
CERTIFICATION
I, Donald E. Brandt, certify that:

1.	 	I have reviewed this Quarterly Report on Form 10-Q of Arizona Public Service Company;	
 		
2.	 	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 		
3.	 	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 		
4.	 	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	

 	a)	 	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 		
 	b)	 	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 		
 	c)	 	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 		
 	d)	 	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	

 

5.	 	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	

 	a)	 	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 		
 	b)	 	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	
Date: May 9, 2007.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	President &
Chief Financial Officer 	 	

  

Exhibit 32.1
CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
          I, William J. Post, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the fiscal quarter ended March 31, 2007, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.
Date: May 9, 2007.

 	/s/ William J. Post  	 	
 	William J. Post 	 	
 	Chairman and Chief Executive Officer 	 	
 	
          I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Pinnacle West Capital Corporation for the fiscal quarter ended March 31, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Pinnacle West Capital Corporation.
Date: May 9, 2007.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	Executive Vice President and
Chief Financial Officer 	 	

 

Exhibit 32.2
CERTIFICATION
OF
CHIEF EXECUTIVE OFFICER
AND
CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
          I, Jack E. Davis, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the fiscal quarter ended March 31, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.
Date: May 9, 2007.

 	/s/ Jack E. Davis  	 	
 	Jack E. Davis 	 	
 	Chief Executive Officer 	 	
 	
          I, Donald E. Brandt, certify, pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Quarterly Report on Form 10-Q of Arizona Public Service Company for the fiscal year ended March 31, 2007 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and that information contained in such Quarterly Report on Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Arizona Public Service Company.
Date: May 9, 2007.

 	/s/ Donald E. Brandt  	 	
 	Donald E. Brandt 	 	
 	President and
Chief Financial Officer 	 	

 
EXHIBIT 99.1
PINNACLE WEST CAPITAL CORPORATION
NON-GAAP FINANCIAL MEASURE RECONCILIATION — OPERATING INCOME
(GAAP MEASURE) TO GROSS MARGIN (NON-GAAP FINANCIAL MEASURE)
(in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	THREE MONTHS ENDED	 	 	 	 	
 	 	MARCH 31,	 	 	Increase (Decrease)	 	
 	 	2007	 	 	2006	 	 	Pretax	 	 	After Tax	 	
Reconciliation of Regulated Electricity Segment	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross Margin	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (closest GAAP measure)	 	$	67,989	 	 	$	57,163	 	 	$	10,826	 	 	$	6,598	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	 	171,578	 	 	 	178,427	 	 	 	(6,849	)	 	 	(4,174	)	
Real estate segment operations	 	 	61,443	 	 	 	71,330	 	 	 	(9,887	)	 	 	(6,026	)	
Depreciation and amortization	 	 	89,621	 	 	 	87,621	 	 	 	2,000	 	 	 	1,219	 	
Taxes other than income taxes	 	 	34,719	 	 	 	35,573	 	 	 	(854	)	 	 	(521	)	
Other expenses	 	 	8,488	 	 	 	8,522	 	 	 	(34	)	 	 	(21	)	
Marketing and trading fuel and purchased power	 	 	57,944	 	 	 	74,175	 	 	 	(16,231	)	 	 	(9,893	)	
Less:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Real estate segment revenues	 	 	77,250	 	 	 	107,854	 	 	 	(30,604	)	 	 	(18,653	)	
Other revenues	 	 	9,363	 	 	 	11,224	 	 	 	(1,861	)	 	 	(1,134	)	
Marketing and trading revenues	 	 	72,471	 	 	 	85,002	 	 	 	(12,531	)	 	 	(7,638	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Regulated Electricity Segment Gross Margin	 	$	332,698	 	 	$	308,731	 	 	$	23,967	 	 	$	14,607	 	

  
 
EXHIBIT 99.2
ARIZONA PUBLIC SERVICE COMPANY
NON-GAAP FINANCIAL MEASURE RECONCILIATION — OPERATING INCOME
(GAAP MEASURE) TO GROSS MARGIN (NON-GAAP FINANCIAL MEASURE)
(in thousands)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	THREE MONTHS ENDED	 	 	 	 	
 	 	MARCH 31,	 	 	Increase (Decrease)	 	
 	 	2007	 	 	2006	 	 	Pretax	 	 	After Tax	 	
Reconciliation of Gross Margin	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operating income (closest GAAP measure)	 	$	40,589	 	 	$	25,044	 	 	$	15,545	 	 	$	9,445	 	
Plus:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Operations and maintenance	 	 	165,934	 	 	 	173,353	 	 	 	(7,419	)	 	 	(4,508	)	
Depreciation and amortization	 	 	87,876	 	 	 	86,311	 	 	 	1,565	 	 	 	951	 	
Income taxes	 	 	3,143	 	 	 	(3,029	)	 	 	6,172	 	 	 	3,750	 	
Other taxes	 	 	34,522	 	 	 	35,548	 	 	 	(1,026	)	 	 	(623	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
Gross Margin	 	$	332,064	 	 	$	317,227	 	 	$	14,837	 	 	$	9,015