Pinnacle West Capital (PNW) 10-Q 2008 Q2 Quarterly report

FORM 10-Q

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

(Mark One)

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

For the quarterly period ended June 30, 2008

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.
1-8962	PINNACLE WEST CAPITAL CORPORATION	86-0512431
	(an Arizona corporation)
	400 North Fifth Street, P.O. Box 53999
	Phoenix, Arizona 85072-3999
	(602) 250-1000
1-4473	ARIZONA PUBLIC SERVICE COMPANY	86-0011170
	(an Arizona corporation)
	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	Yesþ Noo
ARIZONA PUBLIC SERVICE COMPANY	Yesþ Noo

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

PINNACLE WEST CAPITAL CORPORATION
Large accelerated filer      þ     Accelerated filer      o     Non-accelerated filer      o      Smaller reporting companyo
ARIZONA PUBLIC SERVICE COMPANY
Large accelerated filer      o     Accelerated filer      o     Non-accelerated filer      þ      Smaller reporting companyo

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

PINNACLE WEST CAPITAL CORPORATION	Yeso Noþ
ARIZONA PUBLIC SERVICE COMPANY	Yeso Noþ

     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 August 4, 2008: 100,733,570
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of August 4, 2008: 71,264,947

     Arizona Public Service Company meets the conditions set forth in General Instruction H(1)(a) and (b) ofForm 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		33
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		44
Item 3. Quantitative and Qualitative Disclosures About Market Risk		67
Item 4. Controls and Procedures		67
Part II		68
Item 1. Legal Proceedings		68
Item 1A. Risk Factors		68
Item 4. Submission of Matters to a Vote of Security Holders		68
Item 5. Other Information		69
Item 6. Exhibits		71
Signatures		74
EX-3.1
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-10.6
EX-10.7
EX-12.1
EX-12.2
EX-12.3
EX-31.1
EX-31.2
EX-31.3
EX-32.1
EX-32.2

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

APSES — APS Energy Services Company, Inc., a subsidiary of the Company

Base Fuel Rate — the portion of APS’ retail base rates attributable to fuel and purchased power costs

Clean Air Act — Clean Air Act, as amended

Company — Pinnacle West Capital Corporation

DOE — United States Department of Energy

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.

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, Inc.

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

Pinnacle West Marketing & Trading — Pinnacle West Marketing & Trading Co., LLC, a subsidiary of the Company

PRP — potentially responsible parties under Superfund

2

PSA — power supply adjustor approved by the ACC to provide for recovery or refund of variations in actual fuel and purchased power costs compared with the Base Fuel Rate

Salt River Project — Salt River Project Agricultural Improvement and Power District

SEC — United States Securities and Exchange Commission

SFAS — Statement of Financial Accounting Standards

Standard & Poor’s — Standard & Poor’s Ratings Services

SunCor — SunCor Development Company, a subsidiary of the Company

Superfund — Comprehensive Environmental Response, Compensation and Liability Act

2005 Deferrals — PSA deferrals related to 2005 replacement power costs associated with Palo Verde outages

2007 Form 10-K — Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2007

VIE — variable interest entity

3

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)

	Three Months Ended
	June 30,
	2008			2007
OPERATING REVENUES
Regulated electricity segment	$	829,478		$	711,293
Real estate segment		36,880			47,819
Marketing and trading		50,673			92,637
Other revenues		9,162			11,153
Total		926,193			862,902
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		327,561			270,337
Real estate segment operations		41,746			45,917
Marketing and trading fuel and purchased power		45,245			74,533
Operations and maintenance		194,909			177,310
Depreciation and amortization		97,784			92,476
Taxes other than income taxes		33,251			34,757
Other expenses		6,822			8,803
Total		747,318			704,133
OPERATING INCOME		178,875			158,769
OTHER
Allowance for equity funds used during construction		5,414			5,195
Other income (Note 14)		3,928			5,869
Other expense (Note 14)		(10,063	)		(3,269	)
Total		(721	)		7,795
INTEREST EXPENSE
Interest charges		51,583			51,827
Capitalized interest		(4,938	)		(5,213	)
Total		46,645			46,614
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		131,509			119,950
INCOME TAXES		17,076			40,713
INCOME FROM CONTINUING OPERATIONS		114,433			79,237
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $12,608 and $(171) (Note 17)		19,429			(243	)
NET INCOME	$	133,862		$	78,994
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		100,653			100,229
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		100,917			100,779
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations — basic	$	1.14		$	0.79
Net income — basic		1.33			0.79
Income from continuing operations — diluted		1.13			0.79
Net income — diluted		1.33			0.78
DIVIDENDS DECLARED PER SHARE	$	0.525		$	0.525

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

4

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
(dollars and shares in thousands, except per share amounts)

	Six Months Ended
	June 30,
	2008			2007
OPERATING REVENUES
Regulated electricity segment	$	1,452,279		$	1,247,344
Real estate segment		84,622			124,951
Marketing and trading		108,131			165,108
Other revenues		17,899			20,516
Total		1,662,931			1,557,919
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		596,939			473,690
Real estate segment operations		89,965			107,253
Marketing and trading fuel and purchased power		96,767			132,477
Operations and maintenance		389,033			348,888
Depreciation and amortization		193,391			181,854
Taxes other than income taxes		66,403			69,476
Other expenses		12,760			17,291
Total		1,445,258			1,330,929
OPERATING INCOME		217,673			226,990
OTHER
Allowance for equity funds used during construction		11,538			9,639
Other income (Note 14)		7,776			8,642
Other expense (Note 14)		(14,971	)		(7,883	)
Total		4,343			10,398
INTEREST EXPENSE
Interest charges		106,349			101,953
Capitalized interest		(10,617	)		(10,020	)
Total		95,732			91,933
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		126,284			145,455
INCOME TAXES		16,519			49,754
INCOME FROM CONTINUING OPERATIONS		109,765			95,701
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $12,728 and $(125) (Note 17)		19,624			(177	)
NET INCOME	$	129,389		$	95,524
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		100,587			100,138
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		100,856			100,718
EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations — basic	$	1.09		$	0.96
Net income — basic		1.29			0.95
Income from continuing operations — diluted		1.09			0.95
Net income — diluted		1.28			0.95
DIVIDENDS DECLARED PER SHARE	$	1.05		$	1.05

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

5

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	June 30,			December 31,
	2008			2007
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	96,548		$	56,321
Customer and other receivables		503,668			456,007
Allowance for doubtful accounts		(2,520	)		(4,782	)
Materials and supplies (at average cost)		158,059			149,759
Fossil fuel (at average cost)		23,480			27,792
Deferred income taxes		—			31,510
Home inventory		83,556			98,729
Assets from risk management and trading activities (Note 10)		153,403			57,605
Other current assets		19,773			33,988
Total current assets		1,035,967			906,929
INVESTMENTS AND OTHER ASSETS
Real estate investments — net		463,558			532,600
Assets from long-term risk management and trading activities (Note 10)		283,381			48,928
Nuclear decommissioning trust (Note 18)		369,473			379,347
Other assets		114,163			117,941
Total investments and other assets		1,230,575			1,078,816
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		12,031,555			11,640,739
Less accumulated depreciation and amortization		4,057,034			4,004,944
Net		7,974,521			7,635,795
Construction work in progress		498,608			625,577
Intangible assets, net of accumulated amortization		102,355			105,746
Nuclear fuel, net of accumulated amortization		97,730			69,271
Total property, plant and equipment		8,673,214			8,436,389
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		22,530			110,928
Other regulatory assets		501,469			514,353
Other deferred debits		114,235			114,794
Total deferred debits		638,234			740,075
TOTAL ASSETS	$	11,577,990		$	11,162,209

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

6

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	June 30,			December 31,
	2008			2007
LIABILITIES AND COMMON STOCK EQUITY
CURRENT LIABILITIES
Accounts payable	$	309,305		$	323,346
Accrued taxes (Note 8)		99,610			269,628
Accrued interest		39,145			39,836
Short-term borrowings		266,451			340,661
Current maturities of long-term debt (Note 4)		122,847			163,773
Customer deposits		78,687			80,010
Deferred income taxes		105,822			—
Liabilities from risk management and trading activities (Note 10)		58,189			24,510
Other current liabilities		103,663			102,685
Total current liabilities		1,183,719			1,344,449
LONG-TERM DEBT LESS CURRENT MATURITIES (NOTE 4)		3,086,185			3,127,125
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,380,734			1,243,743
Regulatory liabilities		806,911			642,564
Liability for asset retirements		267,544			281,903
Liabilities for pension and other postretirement benefits (Note 6)		529,875			504,603
Liabilities from long-term risk management and trading activities (Note 10)		29,719			4,701
Other		545,490			481,510
Total deferred credits and other		3,560,273			3,159,024
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
COMMON STOCK EQUITY
Common stock, no par value		2,138,841			2,135,787
Treasury stock		(3,398	)		(2,054	)
Total common stock		2,135,443			2,133,733
Accumulated other comprehensive income (loss) (Note 11):
Pension and other postretirement benefits		(44,306	)		(39,336	)
Derivative instruments		219,391			23,473
Total accumulated other comprehensive income (loss)		175,085			(15,863	)
Retained earnings		1,437,285			1,413,741
Total common stock equity		3,747,813			3,531,611
TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,577,990		$	11,162,209

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

7

PINNACLE WEST CAPITAL CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)

	Six Months Ended
	June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	129,389		$	95,524
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		209,355			198,291
Deferred fuel and purchased power		(25,867	)		(132,016	)
Deferred fuel and purchased power amortization		114,265			140,925
Deferred fuel and purchased power regulatory disallowance		—			14,370
Allowance for equity funds used during construction		(11,538	)		(9,639	)
Deferred income taxes		154,249			(3,333	)
Change in mark-to-market valuations		(29,369	)		2,324
Changes in current assets and liabilities:
Customer and other receivables		(37,327	)		21,925
Materials, supplies and fossil fuel		(3,988	)		(23,495	)
Other current assets		22,531			3,810
Accounts payable		(399	)		(13,644	)
Other current liabilities		(24,373	)		64,091
Expenditures for real estate investments		(15,614	)		(73,095	)
Other changes in real estate assets		6,357			19,808
Change in margin and collateral accounts		251,299			(56,546	)
Change in unrecognized tax benefits		(115,337	)		—
Change in other long-term assets		9,088			(20,138	)
Change in other long-term liabilities		46,115			61,158
Net cash flow provided by operating activities		678,836			290,320
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(477,269	)		(453,839	)
Contributions in aid of construction		22,970			16,055
Capitalized interest		(10,617	)		(10,020	)
Proceeds from sale of investment securities		—			69,225
Purchases of investment securities		—			(36,525	)
Proceeds from nuclear decommissioning trust sales		188,311			133,463
Investment in nuclear decommissioning trust		(198,682	)		(143,834	)
Proceeds from sale of commercial real estate investments		94,171			—
Other		1,977			(2,981	)
Net cash flow used for investing activities		(379,139	)		(428,456	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		63,127			133,060
Repayment of long-term debt		(147,467	)		(68,801	)
Short-term borrowings and payments — net		(74,210	)		104,594
Dividends paid on common stock		(105,592	)		(105,110	)
Common stock equity issuance		5,562			17,930
Other		(890	)		(7,275	)
Net cash flow (used for) provided by financing activities		(259,470	)		74,398
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		40,227			(63,738	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		56,321			87,210
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	96,548		$	23,472
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes, net of refunds	$	10,809		$	40,714
Interest, net of amounts capitalized	$	93,734		$	89,916

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

8

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Consolidation and Nature of Operations

     The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, SunCor, APSES, El Dorado and Pinnacle West Marketing & Trading. 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.

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. These condensed consolidated statements and notes should be read in conjunction with the consolidated financial statements and related notes included in our 2007 Form 10-K. These condensed consolidated financial statements and notes have been prepared consistently with the 2007 Form 10-K with the exception of the following items: (1) we have reclassified certain prior-year real estate segment revenues and expenses to discontinued operations on our Condensed Consolidated Statements of Income in accordance with SFAS No. 144; (2) we have netted certain prior-year amounts on our Condensed Consolidated Balance Sheets and Statements of Cash Flows to reflect the adoption of FASB Staff Position No. FIN 39-1 (see Note 10); and (3) “contributions in aid of construction” was previously reported as part of “capital expenditures” on the Condensed Consolidated Statements of Cash Flows. This item has been disclosed separately to provide more detail.

3. Quarterly Fluctuations

     Weather conditions cause significant seasonal fluctuations in our revenues. In addition, real estate activities can have significant impacts on our results for interim periods. For these reasons, results for interim periods do not necessarily represent results expected for the year.

4. Liquidity Matters

     The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements as of June 30, 2008 (dollars in millions):

	Consolidated
Year	Pinnacle West	APS
2008	$103	$—
2009	48	1
2010	226	224
2011	578	401
2012	376	376
Thereafter	1,886	1,884
Total	$3,217	$2,886

9

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     The interest rates on eleven issues of APS’ pollution control bonds, in the aggregate amount of approximately $343 million, are reset every seven days through auction processes. These bonds are supported by bond insurance policies provided by Ambac Assurance Corporation, and the interest rates on the bonds can be directly affected by the rating of the bond insurer. Certain bond insurers have had actual or potential downgrades of their “AAA” credit ratings due to their insuring certain mortgage-backed securities and collateralized debt obligations. Downgrades of bond insurers also increase the possibility of a “failed auction,” which results in higher interest rates during the failed auction periods. During the first quarter of 2008, we had seven failed auctions, which represented about 5% of all of our auctions for the quarter. When the auctions failed, the bondholders received the maximum 14% annual interest rate for the week of the failed auction. The bonds were successfully re-auctioned the following week. We had no failed auctions during the second quarter of 2008 and the average interest rate at the end of the quarter on the auction rate securities was 4.8%. We continue to monitor this market. We do not expect, however, that our auction rate interest exposure will have a material adverse impact on our financial position, results of operations, cash flows or liquidity.

     An existing ACC order requires APS to maintain a common equity ratio of at least 40%. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At June 30, 2008, APS’ common equity ratio, as defined, was 55%, its total common equity was approximately $3.6 billion, and its total capitalization was approximately $6.5 billion. APS would be prohibited from paying dividends if its common equity falls below approximately $2.6 billion, assuming APS’ total capitalization remains the same.

     SunCor has a $150 million loan facility secured primarily by an interest in land, commercial properties, land contracts and homes under construction. The loan facility requires compliance with certain loan covenants pertaining to debt to net worth, debt service, liquidity, cash flow coverage and restrictions on debt. As of June 30, 2008, the amount of SunCor’s net assets that could not be transferred to Pinnacle West in the form of cash dividends as a result of these covenants was approximately $224 million.

     As a result of the restrictions in the preceding two paragraphs, as of June 30, 2008, the restricted net assets of our subsidiaries exceeded 25% of our consolidated net assets (at June 30, 2008, our consolidated net assets were approximately $3.7 billion). These restrictions do not materially affect Pinnacle West’s ability to meet its ongoing capital requirements.

     5. Regulatory Matters

     2008 General Rate Case

     On June 2, 2008, APS filed with the ACC updated financial statements, testimony and other data in the general rate case originally filed on March 24, 2008. As requested by the ACC staff, the updated information reflects a test year ended December 31, 2007, rather than the September 30, 2007 test year used in APS’ original filing. As a result of the updated filing, APS is requesting a net rate increase of $278.2 million for retail customers effective no later than October 1, 2009. As proposed by APS, the updated request would result in an average rate increase of 8.5% for existing customers plus the establishment of a new growth-related impact fee charged to new connections. A hearing on this case is scheduled to begin on April 2, 2009.

10

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     The key financial provisions of the request include:

• an increase of $264.3 million in non-fuel base rates and a net increase of $13.9 million for fuel and purchased power costs reflected in base rates, and recovery of up to $53 million of such increases through the impact fee;

• a rate base of $5.4 billion, which approximates the ACC-jurisdictional portion of the book value of utility assets, net of accumulated depreciation and other credits, as of December 31, 2007, which includes certain adjustments, such as the inclusion of Units 5 and 6 of the Yucca Power Plant (near Yuma in southwestern Arizona), the steam generator replacement at Palo Verde Unit 3, environmental upgrades to APS coal plants, and other plant additions under construction at the end of the test year that are currently in service or expected to go into service before the proposed rates are requested to become effective;

• the following proposed capital structure and costs of capital:

	Capital			Cost of
	Structure			Capital
Long-term debt		46.2	%		5.77	%
Common stock equity		53.8	%		11.50	%
Weighted-average cost of capital					8.86	%

• a Base Fuel Rate of $0.0388 per kWh based on estimated 2010 prices (an increase from the current Base Fuel Rate of $0.0325 per kWh, including the reclassification of $170 million of fuel and purchased power revenues from the PSA to base rates);

• an attrition adjustment of $79.3 million to address erosion in APS’ earnings and return on equity through 2010; and

• a new super-peak residential time-of-use rate and a commercial and industrial critical peak pricing proposal to allow eligible customers additional options to manage their electric bills, as well as other conservation-related rate design proposals.

     The update also requests that the ACC adopt certain goals for APS to improve its financial strength, which include: allowing APS’ internal cash flow generation to cover its operating and capital costs of providing service; stabilizing and improving APS’ credit ratings; and providing a meaningful and ongoing opportunity for APS to achieve a reasonable return on the fair value of its property.

     In addition, APS requested various modifications to the Environmental Improvement Surcharge and the Demand Side Management Adjustment Clause that will allow APS to expand its conservation and demand-side management programs and support environmental upgrades to APS facilities in response to and in anticipation of future environmental requirements.

11

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     Motion for Approval of Interim Rate

     On June 6, 2008, APS filed with the ACC a motion in its currently pending retail rate case, requesting an interim base rate surcharge that would be subject to refund pending the final outcome of the rate case. The motion requested that the interim base rate surcharge of $0.003987 per kWh become effective upon the expiration of the $0.003987 per kWh 2007 PSA charge (the “2007 PSA Adjustor”), the latter of which remained in effect through the last billing cycle in July 2008. On June 30, 2008, APS submitted a proposed schedule to the ACC ALJ, with a goal to resolve the motion by November 2008, without otherwise changing the nature or amount of the request. The proposed procedural schedule was approved by the ACC ALJ on July 16, 2008, with a hearing scheduled to begin September 15, 2008. Rather than becoming effective upon the expiration of the 2007 PSA Adjustor, APS proposed that the interim rates, if approved, would be reflected in customer bills during the month of November when APS switches from summer to winter rates, which are generally lower than summer rates by an amount that is more than the requested interim relief.

     The purpose of the interim surcharge is to better position APS to fund customer-centered programs and needed infrastructure, access needed capital on reasonable terms, minimize the risk of credit rating downgrades by improving APS’ credit metrics until the ACC is able to grant permanent rate relief, allow APS to partially recover already incurred costs related to necessary capital expenditure programs to serve its customers, and provide a better opportunity for APS to achieve a return on equity closer to the level deemed reasonable and approved by the ACC in APS’ last rate case. The interim base rate surcharge would produce approximately $115 million in annual pretax retail revenues. APS cannot currently predict the outcome of this matter.

     2007 Retail Rate Order

     As previously disclosed, in June 2007 the ACC issued an order (the “Retail Rate Order”) in a general retail rate case that APS filed in late 2005. The Retail Rate Order approved a $322 million increase in APS’ annual retail base revenues, effective July 1, 2007, which included a $315 million fuel-related increase and a $7 million non-fuel related increase. The Retail Rate Order also authorized APS’ recovery of approximately $34 million of 2005 Deferrals through a temporary PSA surcharge over a twelve-month period beginning July 1, 2007, modified the PSA in various respects and increased the Base Fuel Rate. In addition, the Retail Rate Order provided that the 2007 PSA Adjustor, which took effect on February 1, 2007 and that was scheduled to expire on January 31, 2008, remain in effect as long as necessary to allow APS to collect $46 million of 2007 fuel and purchased power costs deferred as a result of the mid-2007 implementation of the new Base Fuel Rate. The 2007 PSA Adjustor expired as of the last billing cycle in July 2008.

     PSA Balance

     The following table shows the changes in the deferred fuel and purchased power regulatory asset for the six months ended June 30, 2008 and 2007 (dollars in millions):

12

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Six Months Ended
	June 30,
	2008			2007
Beginning balance	$	111		$	160
Deferred fuel and purchased power costs-current period		25			129
Regulatory disallowance		—			(14	)
Interest on deferred fuel and purchased power		1			3
Amounts recovered through revenues		(114	)		(141	)
Ending balance	$	23		$	137

     The PSA rate for the PSA Year (February 1 through January 31) beginning February 1, 2008 was set at the maximum $0.004 per kWh. Any uncollected deferrals during the 2008 PSA Year resulting from this limit will be included in the historical component of the PSA rate for the PSA Year beginning February 1, 2009.

     Rate Request for a Formula Transmission Tariff

     On July 10, 2007, APS submitted a revised Open Access Transmission Tariff filing with the FERC to move from fixed rates to a formula rate-setting methodology in order to more accurately reflect the costs that APS incurs in providing transmission services. The originally requested formula rate, based on fiscal year 2006 data, proposed an estimated $37 million increase in annual transmission revenues, effective October 1, 2007. The proposed formula rate would be updated each year effective June 1 on the basis of APS’ actual cost of service, as disclosed in APS’ FERC Form 1 report for the previous fiscal year, and projected capital expenditures. Approximately $30 million of the originally requested increase represented charges for transmission services to serve APS’ retail customers (“Retail Transmission Charges”).

     On September 21, 2007, the FERC issued an order on the proposed revisions to APS’ transmission rates in which it accepted APS’ proposed formula rates and ordered settlement judge procedures. The proposed rates became effective March 1, 2008, subject to refund based upon the ultimate outcome of proceedings at the FERC on this matter.

     In order to recover the Retail Transmission Charges authorized by the FERC described above, on December 31, 2007, APS filed with the ACC an application to increase annual pretax retail revenues by approximately $30 million, effective March 1, 2008. This retail rate increase implemented an ACC-approved mechanism, the transmission cost adjustor (“TCA”), by which changes in Retail Transmission Charges can be reflected in APS’ retail rates. On February 13, 2008, the ACC voted to approve APS’ request, subject to refund pending final outcome of FERC proceedings on this matter.

     APS and intervening parties reached and filed a proposed settlement with the FERC on May 29, 2008 that contained some minor variations from the originally proposed formula method used for calculation of the rates. Through the proposed settlement, APS agreed to an initial increase of $28 million in annual transmission revenues, of which $27 million represents Retail Transmission Charges. Pursuant to the proposed settlement agreement, refund of any difference between the originally requested amount and the amount agreed to in the settlement will be netted against the next annual rate

13

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

change. On July 25, 2008, the FERC approved the rates and substance of the settlement through a conditional approval of the settlement, subject to the parties’ revision of a procedural provision.

     In addition, during the period of settlement discussions described above, APS filed calculations with the FERC, based on fiscal year 2007 data, which resulted in the automatic adjustment on June 1, 2008 of our transmission rates under the formula mechanism (as modified in accordance with the proposed settlement at that time). As a result, APS filed a new request with the ACC to allow APS to reflect the resulting increased Retail Transmission Charges in its retail rates through the TCA. On July 3, 2008, the ACC issued an order approving this request. These calculations produced an increase in annual transmission revenues of $15 million, of which $13 million represents Retail Transmission Charges. Also on July 3, 2008, the ACC agreed to follow the refund method contained in the settlement agreement by allowing for the refund of any difference between the originally requested amounts and the amounts resulting from the settlement to be netted against the next annual change in Retail Transmission Charges under the TCA.

     Equity Infusion Notice

     On May 2, 2008, Pinnacle West filed a notice with the ACC that would allow Pinnacle West to infuse up to $400 million of equity into APS in the event Pinnacle West deems it appropriate to do so to strengthen or maintain APS’ financial integrity. Under Arizona law and implementing regulatory decisions, Pinnacle West is required to give such notice at least 120 days prior to an equity infusion into APS that exceeds $150 million in a single calendar year. On July 2, 2008, the ACC staff recommended approval of the proposed infusion, and on July 29, 2008, the ACC voted to approve the recommended order which permits the infusion to occur on or before December 31, 2009.

Federal

     FERC Order

     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APSES (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’ authority to make sales at market-based rates 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.

     On August 13, 2007, the FERC issued an order on rehearing, reinstating the authority of the Pinnacle West Companies to make sales at market-based rates in all seasons for sales outside of the Phoenix Valley, and in all seasons except the summer for sales within the Phoenix Valley. The Pinnacle West Companies submitted a compliance filing implementing this order to the FERC on

14

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

October 12, 2007. This compliance filing was accepted conditionally by FERC in an order issued January 17, 2008. In compliance with the January 17, 2008 order, the Pinnacle West Companies filed a revised mitigation plan to implement cost-based rates for sales in the Phoenix Valley during the summer months. On May 30, 2008, the FERC issued a letter order accepting our mitigation plan. The first summer period under this cost-based mitigation began on June 1, 2008. This proceeding is now concluded.

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 and six months ended June 30, 2008 and 2007. 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						Six Months						Three Months						Six Months
	Ended June 30,						Ended June 30,						Ended June 30,						Ended June 30,
	2008			2007			2008			2007			2008			2007			2008			2007
Service cost-benefits earned during the period	$	13		$	12		$	26		$	25		$	4		$	3		$	9		$	9
Interest cost on benefit obligation		28			23			55			50			9			5			19			18
Expected return on plan assets		(30	)		(25	)		(59	)		(53	)		(11	)		(6	)		(22	)		(21	)
Amortization of:
Transition obligation		—			—			—			—			1			—			2			2
Prior service cost		—			1			1			2			—			—			—			—
Net actuarial loss		2			4			6			8			—			1			1			2
Net periodic benefit cost	$	13		$	15		$	29		$	32		$	3		$	3		$	9		$	10
Portion of cost charged to expense	$	5		$	7		$	12		$	14		$	1		$	1		$	4		$	5
APS’ share of costs charged to expense	$	5		$	6		$	12		$	13		$	1		$	1		$	4		$	4

Contributions

     The contribution to our pension plan in 2008 is estimated to be approximately $35 million. The contribution to our other postretirement benefit plans in 2008 is estimated to be approximately $20 million, of which $10 million has been contributed through August 2008. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of the plans.

7. Business Segments

     Pinnacle West’s two reportable business segments are:

15

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 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.

     Financial data for the three and six months ended June 30, 2008 and 2007 and at June 30, 2008 and December 31, 2007 is provided as follows (dollars in millions):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008		2007
Operating Revenues:
Regulated electricity segment	$	829		$	712	$	1,452	$	1,248
Real estate segment		37			48		85		125
All other (a)		60			103		126		185
Total	$	926		$	863	$	1,663	$	1,558
Net Income:
Regulated electricity segment	$	121		$	71	$	114	$	74
Real estate segment		15			—		14		10
All other (a)		(2	)		8		1		12
Total	$	134		$	79	$	129	$	96

	As of		As of
	June 30, 2008		December 31, 2007
Assets:
Regulated electricity segment	$	10,863	$	10,356
Real estate segment		577		661
All other (a)		138		145
Total	$	11,578	$	11,162

(a) Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.

     8. Income Taxes

     As a result of a change in IRS guidance, we previously claimed a tax deduction related to an APS tax accounting method change on our 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 on our 2002 financial statements. Our 2001 return was the subject of an IRS review and the IRS finalized its examination in the second quarter of 2008, which included a settlement on the tax accounting method change and favorable

16

PINNACLE WEST CAPITAL CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

resolution of other various tax matters. As a result of this settlement and the lapse of federal statutes prior to 2004, we recognized income tax benefits of approximately $30 million in the second quarter of 2008, including approximately $23 million related to interest. Additionally, the settlement and lapse of federal statutes resulted in a net decrease in uncertain tax positions of $115 million through June 30, 2008.

     As of June 30, 2008, the tax year ended December 31, 2004 and all subsequent tax years remain subject to examination by the IRS. With few exceptions, we are no longer subject to state income tax examinations by tax authorities for years before 1999.

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 June 30, 2008, APS would have been required to assume approximately $188 million of debt and pay the equity participants approximately $169 million.

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 June 30, 2008, we hedged exposures to the price variability of the power and gas commodities for a maximum of 39 months. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions.

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 and six months ended June 30, 2008 and 2007 are comprised of the following (dollars in thousands):

17

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Gains on the ineffective portion of derivatives qualifying for hedge accounting	$	1,315	$	422	$	2,405	$	1,333
Gains from the discontinuance of cash flow hedges		—		—		—		314

     During the next twelve months ending June 30, 2009, we estimate that a net gain of $182 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 gains 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.

FIN 39-1

     We adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), on January 1, 2008. In accordance with this guidance, we elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. Collateral was previously reported in other current assets or other current liabilities on our Condensed Consolidated Balance Sheets. This guidance required retrospective application for all prior periods presented. As a result, our Condensed Consolidated Balance Sheet and Statement of Cash Flows line items changed by the following amounts (dollars in thousands):

	As originally		Reclassifications
	reported in the		as a result of the
	2007		adoption of			After adoption of
Balance Sheet — December 31, 2007	Form 10-K		FIN 39-1			FIN 39-1
Current Assets — Assets from risk management and trading activities	$	97,373	$	(39,768	)	$	57,605
Current Assets — Other current assets		34,738		(750	)		33,988
Investments and Other Assets — Assets from long-term risk management and trading activities		89,913		(40,985	)		48,928
Current Liabilities — Liabilities from risk management and trading activities		65,028		(40,518	)		24,510
Deferred Credits and Other - Liabilities from long-term risk management and trading activities		45,686		(40,985	)		4,701

18

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	As originally			Reclassifications
	reported in the			as a result of the
Statement of Cash Flows —	June 30, 2007			adoption of			After adoption of
Six months ended June 30, 2007	Form 10-Q			FIN 39-1			FIN 39-1
Change in margin and collateral accounts(a)	$	11,029		$	(67,575	)	$	(56,546	)
Change in risk management and trading — liabilities		15,883			20,872			36,755	(b)
Collateral		(46,703	)		46,703			—

(a)	Previously referred to as “Change in risk management and trading — assets” in the Quarterly Report on Form 10-Q for the quarter ended June 30, 2007.
(b)	Risk management and trading — liabilities are netted with other long-term liabilities on the Condensed Consolidated Statement of Cash Flows.

     The following tables summarize our assets and liabilities from risk management and trading activities presented net in accordance with FIN 39-1 (dollars in thousands):

				Investments						Deferred
	Current			and Other			Current			Credits and			Net Asset
June 30, 2008	Assets			Assets			Liabilities			Other			(Liability)
Mark-to-market	$	353,722		$	303,089		$	(58,189	)	$	(29,719	)	$	568,903
Margin account		(138,349	)		1,141			—			—			(137,208	)
Collateral provided to counterparties		1,800			—			—			—			1,800
Collateral provided from counterparties		(63,770	)		(20,849	)		—			—			(84,619	)
Total	$	153,403		$	283,381		$	(58,189	)	$	(29,719	)	$	348,876

			Investments					Deferred
	Current		and Other		Current			Credits and
December 31, 2007	Assets		Assets		Liabilities			Other			Net Asset
Mark-to-market	$	26,333	$	48,928	$	(30,786	)	$	(4,701	)	$	39,774
Margin account		30,650		—		6,148			—			36,798
Collateral provided to counterparties		622		—		128			—			750
Collateral provided from counterparties		—		—		—			—			—
Total	$	57,605	$	48,928	$	(24,510	)	$	(4,701	)	$	77,322

     We maintain a margin account with a broker to support our risk management and trading activities. 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.

19

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

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 10% of Pinnacle West’s $437 million of risk management and trading assets as of June 30, 2008. 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

     Components of comprehensive income for the three and six months ended June 30, 2008 and 2007 are as follows (dollars in thousands):

20

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months						Six Months
	Ended June 30,						Ended June 30,
	2008			2007			2008			2007
Net income	$	133,862		$	78,994		$	129,389		$	95,524
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		240,986			(32,880	)		360,792			29,680
Net reclassification of realized gains to income (b)		(36,705	)		(14,049	)		(38,771	)		(19,061	)
Net unrealized losses related to pension and other postretirement benefits (c)		(10,595	)		(44,573	)		(10,595	)		(44,573	)
Reclassification of pension and other postretirement benefits to income		1,304			228			2,347			479
Income tax benefit (expense) related to items of other comprehensive income		(76,344	)		35,724			(122,825	)		13,154
Total other comprehensive income (loss)		118,646			(55,550	)		190,948			(20,321	)
Comprehensive income	$	252,508		$	23,444		$	320,337		$	75,203

(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 for contracted commodities delivered during the period.

(c) In accordance with the ACC’s June 28, 2007 order in APS’ general rate case, these amounts primarily include costs that were recorded previously as a regulatory asset and have now been charged to other comprehensive income.

21

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 and trial is expected to occur in 2009.

     APS currently estimates it will incur $132 million (in 2008 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 June 30, 2008, APS had a regulatory liability of $17 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

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. In addition, on March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including APS, failed to properly file rate information at the FERC in connection with sales to California from 2000 to March 2002 under market-based rates. Since 2004, the Ninth Circuit and the FERC have issued various decisions and orders involving the aforementioned issues, including decisions related to: entities subject to FERC jurisdiction and, therefore, potentially owing refunds; applicable refund methodologies; the temporal scope and types of transactions that are properly subject to the refund orders; and the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings. A settlement, resolving APS’ issues with certain California parties for the current refund period, was approved by the FERC in an order issued on June 30, 2008. The resolution of the claims related to the parties involved in this settlement had no material adverse impact on our financial position, results of operations or cash flows. We currently believe the refund claims at the FERC related to the parties not involved in this settlement will have no 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

22

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 sought rehearing of this order; however, under the settlement agreement mentioned above, these parties withdrew their request for rehearing on July 22, 2008.

     On July 25, 2001, 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 was appealed to the U.S. Court of Appeals for the Ninth Circuit. On August 24, 2007, the Ninth Circuit issued an opinion that remanded the proceeding to the FERC for further consideration. Petitions for rehearing of this opinion were filed. Although the FERC has not yet determined whether any refunds will ultimately be required, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or cash flows.

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 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. On July 10, 2008, Peabody agreed to dismiss this litigation without prejudice. APS cannot currently predict whether the lawsuit will be refiled based upon the final outcome of the D.C. Lawsuit.

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

23

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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, at the present time neither APS nor Pinnacle West can accurately estimate the expenditures that may be required.

Salt River Project

     Salt River Project has notified APS that Salt River Project allegedly failed to bill APS for (a) energy losses under certain service schedules of a power contract between the parties and (b) certain other charges under the contract. Salt River Project asserts that certain of these failures to bill APS for such losses and charges may extend back to 1996 and, as a result, claims that APS owes it approximately $29 million. APS disputes that it is required to pay these amounts. No lawsuit or litigation has been initiated in the matter at this time. We do not expect that resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.

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 financial position, results of operations or cash flows.

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.

     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 $20.8 million.

24

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     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 and six months ended June 30, 2008 and 2007 (dollars in thousands):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Other income:
Interest income	$	3,233		$	1,950		$	5,476		$	5,362
Investment gains — net		—			2,681			—			942
SunCor other income (a)		42			778			1,638			1,358
Miscellaneous		653			460			662			980
Total other income	$	3,928		$	5,869		$	7,776		$	8,642
Other expense:
Non-operating costs	$	(3,594	)	$	(2,344	)	$	(5,524	)	$	(5,655	)
Investment losses — net		(5,540	)		—			(8,208	)		—
Miscellaneous		(929	)		(925	)		(1,239	)		(2,228	)
Total other expense	$	(10,063	)	$	(3,269	)	$	(14,971	)	$	(7,883	)

(a) Includes equity earnings from a real estate joint venture that is a pass-through entity for tax purposes.

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 and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require performance under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our 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 June 30, 2008 are as follows (dollars in millions):

25

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Marketing & Trading	$	12		1	$	—		—
APSES		18		1		11		1
APS		4		1		—		—
Total	$	34			$	11

     At June 30, 2008, Pinnacle West had approximately $7 million of letters of credit related to workers’ compensation expiring in 2009. 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 June 30, 2008, 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 on such debt obligations and expire in 2010. APS has also entered into approximately $79 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 June 30, 2008, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2008. 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 and six months ended June 30, 2008 and 2007:

26

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008		2007			2008		2007
Basic earnings per share:
Income from continuing operations	$	1.14	$	0.79		$	1.09	$	0.96
Income (loss) from discontinued operations		0.19		—			0.20		(0.01	)
Earnings per share — basic	$	1.33	$	0.79		$	1.29	$	0.95
Diluted earnings per share:
Income from continuing operations	$	1.13	$	0.79		$	1.09	$	0.95
Income (loss) from discontinued operations		0.20		(0.01	)		0.19		—
Earnings per share — diluted	$	1.33	$	0.78		$	1.28	$	0.95

     Dilutive stock options and performance shares (which are contingently issuable) increased average common shares outstanding by approximately 264,000 shares and 550,000 shares for the three months ended June 30, 2008 and June 30, 2007 respectively, and by approximately 269,000 shares and 580,000 shares for the six months ended June 30, 2008 and 2007 respectively.

     Options to purchase 713,291 shares of common stock for the three-month period and 688,167 shares for the six-month period ended June 30, 2008 were outstanding but were excluded from the computation of diluted earnings per share because the options’ exercise prices were greater 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 for that same reason were 113,250 shares for the three-month period ended June 30, 2007. There were no such options outstanding for the six-month period ended June 30, 2007.

17. Discontinued Operations

     SunCor (real estate segment)-In 2008 and 2007, SunCor sold or expects to sell commercial properties that 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 and six months ended June 30, 2008 and 2007 (dollars in millions):

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2008		2007	2008		2007
Revenue	$	—	$ 1	$	—	$	3
Income before income taxes		32	—		32	—
Income after income taxes		20	—		20	—

27

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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 securities and domestic 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 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, we have recorded the offsetting amount of gains (losses) on investment securities in other regulatory liabilities or assets.The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at June 30, 2008 and December 31, 2007 (dollars in millions):

	Trust Fund		Total Unrealized
	Assets		Gains
June 30, 2008
Equity securities — fair value	$	154	$	47
Fixed income securities — fair value		215		3
Total	$	369	$	50
December 31, 2007
Equity securities — fair value	$	175	$	68
Fixed income securities — fair value		204		5
Total	$	379	$	73

     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						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Realized gains	$	1		$	1		$	2		$	2
Realized losses		(1	)		(1	)		(2	)		(3	)
Proceeds from the sale of securities		121			70			188			133

     The fair value of fixed income securities, summarized by contractual maturities, at June 30, 2008 is as follows (dollars in millions):

28

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value	June 30, 2008
Less than one year	$	13
1 year — 5 years		37
5 years — 10 years		45
Greater than 10 years		120
Total	$	215

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

19. New Accounting Standards

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

     See Notes 10 and S-1 for discussions of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we adopted January 1, 2008.

     SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” was effective for us on January 1, 2008. This guidance provides companies with an option to report selected financial assets and liabilities at fair value. We did not elect the fair value option for any of our financial assets or liabilities. Therefore, SFAS No. 159 did not have an impact on our financial statements.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This guidance requires enhanced disclosures about derivative instruments and hedging activities. The Statement is effective for us on January 1, 2009. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.

20. Fair Value Measurements

     We adopted SFAS No. 157, “Fair Value Measurements,” on January 1, 2008. This new standard defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. We apply fair value measurements to derivative instruments and nuclear decommissioning trust assets. The adoption of SFAS No. 157 did not have a material impact on our financial statements.

     SFAS No. 157 requires companies to disclose the fair value of certain assets and liabilities according to a fair value hierarchy. This hierarchy ranks the quality and reliability of the inputs used to determine fair values, which are then classified and disclosed in one of three categories. The three levels of the fair value hierarchy are:

• Level 1 — quoted prices in active markets for identical assets or liabilities.

• Level 2 — quoted prices in active markets for similar assets or liabilities; quoted prices in markets that are not active; and model-derived valuations whose inputs are observable.

29

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

• Level 3 – model-derived valuations with unobservable inputs that are supported by little or no market activity.

     As required by SFAS No. 157, assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following table presents the fair value at June 30, 2008 of our assets and liabilities that are measured at fair value on a recurring basis for both Pinnacle West Consolidated and APS (dollars in millions):

	Quoted Prices
	in Active			Significant
	Markets for			Other			Significant
	Identical			Observable			Unobservable						Balance at
	Assets			Inputs			Inputs			Counterparty			June 30,
Pinnacle West:	(Level 1)			(Level 2)			(Level 3)			Netting			2008
Assets
Risk management and trading activities (a)	$	239		$	563		$	72		$	(217	)	$	657
Nuclear decommissioning trust		33			336			—			—			369
Total	$	272		$	899		$	72		$	(217	)	$	1,026
Liabilities
Risk management and trading activities (a)	$	(65	)	$	(175	)	$	(65	)	$	217		$	(88	)
APS:
Assets
Risk management and trading activities (a)	$	239		$	515		$	72		$	(208	)	$	618
Nuclear decommissioning trust		33			336			—			—			369
Total	$	272		$	851		$	72		$	(208	)	$	987
Liabilities
Risk management and trading activities (a)	$	(65	)	$	(149	)	$	(65	)	$	208		$	(71	)

30

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(a) Excludes $137 million of margin account liability and net collateral of $83 million. See Notes 10 and S-1.

     The following table shows the changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2008 for Pinnacle West Consolidated (dollars in millions):

	Three Months Ended			Six Months Ended
	June 30, 2008			June 30, 2008
Net derivative asset balance at beginning of period	$	7		$	8
Total net gains (losses) realized/ unrealized:
Included in earnings		(17	)		(19	)
Included in OCI		11			13
Deferred as a regulatory asset or liability		(2	)		(5	)
Purchases, issuances, and settlements		—			—
Transfers into Level 3(a)		8			10
Net derivative asset balance at end of period	$	7		$	7
Net unrealized losses included in earnings related to instruments still held as of June 30, 2008	$	16		$	18

(a) Transfers reflect fair value as of the beginning of the quarter.

     The following table shows the changes in fair value for assets and liabilities that are measured at fair value on a recurring basis using Level 3 inputs for the three and six months ended June 30, 2008 for APS (dollars in millions):

31

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended			Six Months Ended
	June 30, 2008			June 30, 2008
Net derivative asset (liability) balance at beginning of period	$	—		$	1
Total net gains (losses) realized/ unrealized:
Included in earnings		(17	)		(19	)
Included in OCI		11			13
Deferred as a regulatory asset or liability		(2	)		(5	)
Purchases, issuances, and settlements		—			—
Transfers into Level 3(a)		15			17
Net derivative asset balance at end of period	$	7		$	7
Net unrealized losses included in earnings related to instruments still held as of June 30, 2008	$	26		$	29

(a) Transfers reflect fair market value as of the beginning of the quarter.

     We did not have any non-recurring fair value measurements during the quarter that required disclosure.

32

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended
	June 30,
	2008			2007
ELECTRIC OPERATING REVENUES	$	831,083		$	721,759
OPERATING EXPENSES
Fuel and purchased power		329,077			273,406
Operations and maintenance		187,819			170,631
Depreciation and amortization		95,961			90,809
Income taxes		21,553			42,682
Other taxes		32,813			34,588
Total		667,223			612,116
OPERATING INCOME		163,860			109,643
OTHER INCOME (DEDUCTIONS)
Income taxes		1,839			(399	)
Allowance for equity funds used during construction		5,414			5,195
Other income (Note S-3)		1,034			4,356
Other expense (Note S-3)		(6,200	)		(2,769	)
Total		2,087			6,383
INTEREST DEDUCTIONS
Interest on long-term debt		40,719			40,400
Interest on short-term borrowings		2,519			2,052
Debt discount, premium and expense		1,160			1,159
Allowance for borrowed funds used during construction		(3,833	)		(2,675	)
Total		40,565			40,936
NET INCOME	$	125,382		$	75,090

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

33

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF INCOME
(unaudited)
(dollars in thousands)

	Six Months Ended
	June 30,
	2008			2007
ELECTRIC OPERATING REVENUES	$	1,456,659		$	1,260,019
OPERATING EXPENSES
Fuel and purchased power		601,130			479,602
Operations and maintenance		375,954			336,565
Depreciation and amortization		189,846			178,685
Income taxes		26,710			45,825
Other taxes		65,531			69,110
Total		1,259,171			1,109,787
OPERATING INCOME		197,488			150,232
OTHER INCOME (DEDUCTIONS)
Income taxes		2,954			355
Allowance for equity funds used during construction		11,538			9,639
Other income (Note S-3)		3,098			8,789
Other expense (Note S-3)		(12,088	)		(7,673	)
Total		5,502			11,110
INTEREST DEDUCTIONS
Interest on long-term debt		82,892			80,475
Interest on short-term borrowings		6,368			4,033
Debt discount, premium and expense		2,320			2,315
Allowance for borrowed funds used during construction		(7,608	)		(4,888	)
Total		83,972			81,935
NET INCOME	$	119,018		$	79,407

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

34

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	June 30,			December 31,
	2008			2007
ASSETS
UTILITY PLANT
Electric plant in service and held for future use	$	11,971,164		$	11,582,862
Less accumulated depreciation and amortization		4,046,556			3,994,777
Net		7,924,608			7,588,085
Construction work in progress		492,531			622,693
Intangible assets, net of accumulated amortization		101,817			105,225
Nuclear fuel, net of accumulated amortization		97,730			69,271
Total utility plant		8,616,686			8,385,274
INVESTMENTS AND OTHER ASSETS
Nuclear decommissioning trust (Note 18)		369,473			379,347
Assets from long-term risk management and trading activities (Note S-1)		282,291			41,603
Other assets		67,593			69,570
Total investments and other assets		719,357			490,520
CURRENT ASSETS
Cash and cash equivalents		85,669			52,151
Customer and other receivables		453,101			402,244
Allowance for doubtful accounts		(2,019	)		(4,265	)
Materials and supplies (at average cost)		158,059			149,759
Fossil fuel (at average cost)		23,480			27,792
Assets from risk management and trading activities (Note S-1)		115,399			34,087
Deferred income taxes		—			38,707
Other current assets		16,018			16,545
Total current assets		849,707			717,020
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		22,530			110,928
Other regulatory assets		501,469			514,353
Unamortized debt issue costs		23,326			24,373
Other deferred debits		82,592			78,934
Total deferred debits		629,917			728,588
TOTAL ASSETS	$	10,815,667		$	10,321,402

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

35

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)

	June 30,			December 31,
	2008			2007
LIABILITIES AND EQUITY
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		2,117,789			2,105,466
Retained earnings		1,110,575			1,076,557
Accumulated other comprehensive income (loss) (Note S-2):
Pension and other postretirement benefits		(26,802	)		(21,782	)
Derivative instruments		205,897			13,038
Common stock equity		3,585,621			3,351,441
Long-term debt less current maturities (Note 4)		2,876,875			2,876,881
Total capitalization		6,462,496			6,228,322
CURRENT LIABILITIES
Short-term debt		100,000			218,000
Current maturities of long-term debt (Note 4)		977			978
Accounts payable		253,827			239,923
Accrued taxes		208,542			374,444
Accrued interest		38,455			38,262
Customer deposits		76,661			71,376
Liabilities from risk management and trading activities (Note S-1)		42,661			19,921
Deferred income taxes		97,182			—
Other current liabilities		98,837			92,802
Total current liabilities		917,142			1,055,706
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,388,921			1,250,028
Regulatory liabilities		806,911			642,564
Liability for asset retirements		267,544			281,903
Pension and other postretirement liabilities (Note 6)		494,227			469,945
Customer advances for construction		121,343			94,801
Liabilities from long-term risk management and trading activities (Note S-1)		28,629			4,573
Other		328,454			293,560
Total deferred credits and other		3,436,029			3,037,374
COMMITMENTS AND CONTINGENCIES (SEE NOTES)
TOTAL LIABILITIES AND EQUITY	$	10,815,667		$	10,321,402

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

36

ARIZONA PUBLIC SERVICE COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(unaudited)
(dollars in thousands)

	Six Months Ended
	June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	119,018		$	79,407
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization including nuclear fuel		205,810			195,122
Deferred fuel and purchased power		(25,867	)		(132,016	)
Deferred fuel and purchased power amortization		114,265			140,925
Deferred fuel and purchased power regulatory disallowance		—			14,370
Allowance for equity funds used during construction		(11,538	)		(9,639	)
Deferred income taxes		152,408			(2,862	)
Changes in mark-to-market valuations		(28,825	)		(3,000	)
Changes in current assets and liabilities:
Customer and other receivables		(47,733	)		5,583
Materials, supplies and fossil fuel		(3,988	)		(23,495	)
Other current assets		1,949			(5,060	)
Accounts payable		35,147			10,492
Other current liabilities		(11,450	)		40,944
Change in margin and collateral accounts		251,299			3,895
Change in unrecognized tax benefits		(112,507	)		—
Change in other long-term assets		4,072			(24,607	)
Change in other long-term liabilities		44,403			44,231
Net cash flow provided by operating activities		686,463			334,290
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(462,598	)		(426,518	)
Contributions in aid of construction		22,970			16,055
Allowance for borrowed funds used during construction		(7,608	)		(4,888	)
Purchases of investment securities		—			(36,525	)
Proceeds from sale of investment securities		—			69,225
Proceeds from nuclear decommissioning trust sales		188,311			133,463
Investment in nuclear decommissioning trust		(198,682	)		(143,834	)
Other		555			(3,321	)
Net cash flow used for investing activities		(457,052	)		(396,343	)
CASH FLOWS FROM FINANCING ACTIVITIES
Equity infusion		7,601			39,548
Short-term borrowings and payments-net		(118,000	)		28,000
Dividends paid on common stock		(85,000	)		(85,000	)
Repayment and reacquisition of long-term debt		(494	)		(566	)
Net cash flow used for financing activities		(195,893	)		(18,018	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		33,518			(80,071	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		52,151			81,870
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	85,669		$	1,799
Supplemental disclosure of cash flow information
Cash paid during the year for:
Income taxes, net of refunds	$	7,197		$	44,424
Interest, net of amounts capitalized	$	81,459		$	78,418

See Notes to Pinnacle West’s Condensed Consolidated Financial Statements and Supplemental Notes to Arizona Public Service Company’s Condensed Financial Statements.

37

     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 that 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		—
Liquidity Matters	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	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		—
Fair Value Measurements	Note 20		—

38

S-1. Derivative and Energy Trading Accounting

     APS uses derivative instruments (primarily forward purchases and sales, swaps, options and futures) to manage its exposure to the commodity price risk inherent in the purchase and sale of fuel, electricity and emission allowances and credits. As of June 30, 2008, APS hedged exposures to the price variability of the power and gas commodities for a maximum of 39 months. The changes in the market value of such contracts have a high correlation to price changes in the hedged transactions.

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 and six months ended June 30, 2008 and 2007 were comprised of the following (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Gains on the ineffective portion of derivatives qualifying for hedge accounting	$	1,315	$	422	$	2,405	$	1,333
Gains from the discontinuance of cash flow hedges		—		—		—		150

     During the next twelve months ending June 30, 2009, APS estimates that a net gain of $161 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 gains 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.

FIN 39-1

     We adopted FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), on January 1, 2008. In accordance with this guidance, we elected to offset the fair value amounts for derivative instruments, including collateral, executed with the same counterparty under a master netting arrangement. Collateral was previously reported in other current assets or other current liabilities on our Condensed Balance Sheets. This guidance required retrospective application for all prior periods presented. As a result, APS’ Condensed Balance Sheet and Statement of Cash Flows line items changed by the following amounts (dollars in thousands):

39

	As originally		Reclassifications
	reported in the		as a result of the
	2007		adoption of			After adoption
Balance Sheet - December 31, 2007	Form 10-K		FIN 39-1			of FIN 39-1
Current Assets — Assets from risk management and trading activities	$	73,854	$	(39,767	)	$	34,087
Current Assets — Other current assets		17,296		(751	)		16,545
Investments and Other Assets — Assets from long-term risk management and trading activities		82,588		(40,985	)		41,603
Current Liabilities — Liabilities from risk management and trading activities		60,439		(40,518	)		19,921
Deferred Credits and Other — Liabilities from long-term risk management and trading activities		45,558		(40,985	)		4,573

	As originally			Reclassifications
	reported in the			as a result of the
Statement of Cash Flows —	June 30, 2007			adoption of			After adoption
Six months ended June 30, 2007	Form 10-Q			FIN 39-1			of FIN 39-1
Change in margin and collateral accounts	$	22,857	(a)	$	(18,962	)	$	3,895
Change in risk management and trading — liabilities		(2,306	)		20,221			17,915	(b)
Collateral		1,259			(1,259	)		—

(a)	Change in margin and collateral accounts were netted with other long-term assets on APS’ Condensed Statement of Cash Flows presented in the Quarterly Report on Form 10-Q for the quarter ended June 30, 2007.
(b)	Risk management and trading — liabilities are netted with other long-term liabilities on APS’ Condensed Statements of Cash Flows.

     The following tables summarize APS’ assets and liabilities from risk management and trading activities presented net in accordance with FIN 39-1 (dollars in thousands):

40

				Investments						Deferred
	Current			and Other			Current			Credits and			Net Asset
June 30, 2008	Assets			Assets			Liabilities			Other			(Liability)
Mark-to-market	$	315,718		$	301,999		$	(42,661	)	$	(28,629	)	$	546,427
Margin account liability		(138,349	)		1,141			—			—			(137,208	)
Collateral provided to counterparties		1,800			—			—			—			1,800
Collateral provided from counterparties		(63,770	)		(20,849	)		—			—			(84,619	)
Total	$	115,399		$	282,291		$	(42,661	)	$	(28,629	)	$	326,400

			Investments					Deferred
	Current		and Other		Current			Credits and
December 31, 2007	Assets		Assets		Liabilities			Other			Net Asset
Mark-to-market	$	2,815	$	41,603	$	(26,197	)	$	(4,573	)	$	13,648
Margin account		30,650		—		6,148			—			36,798
Collateral provided to counterparties		622		—		128			—			750
Collateral provided from counterparties		—		—		—			—			—
Total	$	34,087	$	41,603	$	(19,921	)	$	(4,573	)	$	51,196

     We maintain a margin account with a broker to support our risk management and trading activities. 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.

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

S-2. Comprehensive Income

     Components of APS’ comprehensive income for the three and six months ended June 30, 2008 and 2007 are as follows (dollars in thousands):

41

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Net income	$	125,382		$	75,090		$	119,018		$	79,407
Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		234,352			(25,781	)		341,368			24,764
Net reclassification of realized gains to income (b)		(26,647	)		(6,270	)		(23,329	)		(5,529	)
Net unrealized losses related to pension benefits (c)		(10,279	)		(44,613	)		(10,279	)		(44,613	)
Reclassification of pension and other postretirement benefits to income		1,206			—			2,001			—
Income tax benefit (expense) related to items of other comprehensive income		(78,182	)		30,082			(121,922	)		9,958
Total other comprehensive income (loss)		120,450			(46,582	)		187,839			(15,420	)
Comprehensive income	$	245,832		$	28,508		$	306,857		$	63,987

(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.
(c)	In accordance with the ACC’s June 28, 2007 order in APS’ general rate case, these amounts primarily include costs that were recorded previously as a regulatory asset and have now been charged to other comprehensive income.

S-3. Other Income and Other Expense

     The following table provides detail of APS’ other income and other expense for the three and six months ended June 30, 2008 and 2007 (dollars in thousands):

42

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
Other income:
Interest income	$	602		$	1,512		$	2,325		$	4,859
Investment gains — net		—			2,141			—			2,518
Miscellaneous		432			703			773			1,412
Total other income	$	1,034		$	4,356		$	3,098		$	8,789
Other expense:
Non-operating costs (a)	$	(2,864	)	$	(2,001	)	$	(6,186	)	$	(5,234	)
Investment losses — net		(1,411	)		—			(2,863	)		—
Miscellaneous		(1,925	)		(768	)		(3,039	)		(2,439	)
Total other expense	$	(6,200	)	$	(2,769	)	$	(12,088	)	$	(7,673	)

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

43

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. Although customer growth in APS’ service territory has recently decreased, as well as our customer growth outlook for the next several years, it is still at or above the national average and remains an important driver of our revenues and earnings.

     Our cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed below under “Liquidity and Capital Resources,” are substantial because of customer growth in APS’ service territory, inflationary impacts on the capital budget and increased generation, environmental and reliability costs, highlighting APS’ need for the timely recovery through rates of these and other expenditures. See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below. On March 24, 2008, and later updated on June 2, 2008, APS filed a rate case with the ACC requesting, among other things, an increase in rates to help defray rising infrastructure costs, approval of an impact fee and approval of new conservation rates. Details of the current ACC rate case, a request for an interim increase related to this rate case, and other retail and wholesale rate matters are discussed in Note 5.

     SunCor, our real estate development subsidiary, has been an important source of earnings in recent years, although SunCor’s earnings in 2007 and expected earnings in 2008 reflect the weak real estate market. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APSES, provides 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.

     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 energy resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.

     See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” below for a discussion of several factors that could affect our future financial results.

44

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

     Pinnacle West’s two reportable 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 presents income from continuing operations for our regulated electricity and real estate segments and reconciles those amounts to net income in total for the three months and six months ended June 30, 2008 and 2007 (dollars in millions):

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2008			2007		2008			2007
Regulated electricity segment	$	121		$	71	$	114		$	74
Real estate segment		(5	)		—		(6	)		10
All other (a)		(2	)		8		1			12
Income from continuing operations		114			79		109			96
Income from discontinued operations, real estate segment — net of tax (b)		20			—		20			—
Net income	$	134		$	79	$	129		$	96

(a)	Includes activities related to marketing and trading, APSES and El Dorado. None of these segments is a reportable segment.
(b)	Primarily relates to a commercial property sale.

PINNACLE WEST CONSOLIDATED — RESULTS OF OPERATIONS

Operating Results — Three-month period ended June 30, 2008 compared with three-month period ended June 30, 2007

     Our consolidated net income for the three months ended June 30, 2008 was $134 million compared with net income of $79 million for the comparable prior-year period. Net income increased $55 million in the period-to-period comparison and is reflected in the segments as follows:

• Regulated Electricity Segment — Net income increased approximately $50 million due to various factors, including income tax benefits of $30 million related to prior years resolved in 2008; the impacts of retail and transmission rate increases; increased mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals; a regulatory disallowance in 2007; increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts; and higher retail sales primarily due to customer growth. These positive factors were partially offset by the effects of milder weather on retail sales; higher operations and maintenance expense primarily related to distribution system reliability, generation costs (including planned maintenance and overhauls), and other costs; and higher depreciation and amortization primarily due to higher plant balances.

45

• Real Estate Segment — Net income increased approximately $15 million primarily due to a commercial property sale in 2008, partially offset by lower land parcel sales resulting from the weak real estate market.

• Other — Net income decreased approximately $10 million primarily due to lower marketing and trading contributions as a result of lower sales volumes.

     Additional details on the major factors that increased (decreased) net income for the three-month period ended June 30, 2008 compared with the prior-year period are contained in the following table (dollars in millions):

46

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment:
Impacts of retail rate increase effective July 1, 2007 and transmission rate increase effective March 1, 2008:
Retail revenue increase primarily related to higher Base Fuel Rate	$	93		$	57
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(76	)		(46	)
Transmission rate increase (including a retail rate component)		7			4
Higher mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		17			10
Regulatory disallowance in 2007		14			8
Increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts		7			4
Higher retail sales primarily due to customer growth, excluding weather effects		6			4
Effects of milder weather on retail sales		(18	)		(11	)
Higher operations and maintenance expense primarily related to distribution system reliability, increased generation costs (including planned maintenance and overhauls), and other costs		(12	)		(7	)
Higher depreciation and amortization primarily due to higher plant balances		(5	)		(3	)
Income tax benefits related to prior years resolved in 2008		—			30
Miscellaneous items, net		2			—
Increase in regulated electricity segment net income		35			50
Lower real estate segment income from continuing operations primarily due to lower land parcel sales resulting from the weak real estate market		(8	)		(5	)
Lower marketing and trading contribution primarily due to lower sales volumes		(13	)		(8	)
Other miscellaneous items, net		(2	)		(2	)
Increase in income from continuing operations	$	12			35
Increase in real estate segment income from discontinued operations primarily related to a commercial property sale					20
Increase in net income				$	55

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $118 million higher for the three months ended June 30, 2008 compared with the prior-year period primarily because of:

• a $93 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $20 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $13 million increase in revenues related to long-term traditional wholesale contracts;

47

• an $8 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $7 million increase due to a transmission rate increase (including a retail rate component) effective March 1, 2008;

• a $24 million decrease in retail revenue due to the effects of milder weather;

• an $8 million decrease 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; and

• a $9 million net increase due to miscellaneous factors.

Real Estate Segment Revenues

     Real estate segment revenues were $11 million lower for the three months ended June 30, 2008 compared with the prior-year period primarily due to lower land parcel and home sales as a result of the weak real estate market.

All Other Revenues

     All other revenues were $44 million lower for the three months ended June 30, 2008 compared with the prior-year period primarily due to the planned reduction of APSES’ retail commodity-related energy services and a decrease in other marketing and trading activities.

Operating Results — Six-month period ended June 30, 2008 compared with six-month period ended June 30, 2007

     Our consolidated net income for the six months ended June 30, 2008 was $129 million compared with net income of $96 million for the comparable prior-year period. Net income increased $33 million in the period-to-period comparison and is reflected in the segments as follows:

• Regulated Electricity Segment — Net income increased approximately $40 million due to various factors, including income tax benefits of $30 million related to prior years resolved in 2008; the impacts of retail and transmission rate increases; increased mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals; a regulatory disallowance in 2007; higher retail sales primarily due to customer growth; and increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts. These positive factors were partially offset by higher operations and maintenance expense primarily related to increased generation costs (including planned maintenance and overhauls), increased costs related to distribution system reliability, and other costs; the effects of milder weather on retail sales; and higher depreciation and amortization primarily due to higher plant balances.

• Real Estate Segment — Net income increased approximately $4 million primarily due to a commercial property sale in 2008, partially offset by lower land parcel sales resulting from the weak real estate market.

48

• Other — Net income decreased approximately $11 million primarily due to lower marketing and trading contributions as a result of lower sales volumes.

     Additional details on the major factors that increased (decreased) net income for the six-month period ended June 30, 2008 compared with the prior-year period are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment:
Impacts of retail rate increase effective July 1, 2007 and transmission rate increase effective March 1, 2008:
Retail revenue increase primarily related to higher Base Fuel Rate	$	156		$	95
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(141	)		(86	)
Transmission rate increase (including a retail rate component)		10			6
Higher mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		26			16
Regulatory disallowance in 2007		14			8
Higher retail sales primarily due to customer growth, excluding weather effects		12			7
Increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts		11			7
Effects of milder weather on retail sales		(19	)		(12	)
Operations and maintenance expense increases primarily due to:
Increased customer service and other costs as a result of distribution system reliability		(18	)		(11	)
Increased generation costs, including more planned maintenance and overhauls		(15	)		(9	)
Higher depreciation and amortization primarily due to higher plant balances		(11	)		(7	)
Income tax benefits related to prior years resolved in 2008		—			30
Miscellaneous items, net		(3	)		(4	)
Increase in regulated electricity segment net income		22			40
Lower real estate segment income from continuing operations primarily due to lower land parcel sales resulting from the weak real estate market		(26	)		(16	)
Lower marketing and trading contribution primarily due to lower sales volumes		(21	)		(13	)
Other miscellaneous items, net		6			2
Increase (decrease) in income from continuing operations	$	(19	)		13
Increase in real estate segment income from discontinued operations primarily related to a commercial property sale					20
Increase in net income				$	33

49

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $205 million higher for the six months ended June 30, 2008 compared with the prior-year period primarily because of:

• a $156 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $37 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $20 million increase in revenues related to long-term traditional wholesale contracts;

• a $16 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $10 million increase due to a transmission rate increase (including a retail rate component) effective March 1, 2008;

• a $26 million decrease 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;

• a $25 million decrease in retail revenue due to the effects of milder weather; and

• a $17 million net increase due to miscellaneous factors.

Real Estate Segment Revenues

     Real estate segment revenues were $40 million lower for the six months ended June 30, 2008 compared with the prior-year period primarily due to lower land parcel sales as a result of the weak real estate market.

All Other Revenues

     All other revenues were $60 million lower for the six months ended June 30, 2008 compared with the prior-year period primarily due to the planned reduction of APSES’ retail commodity-related energy services and a decrease in other marketing and trading activities.

50

PINNACLE WEST CONSOLIDATED — LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

     The following table presents net cash provided by (used for) operating, investing and financing activities for the six months ended June 30, 2008 and 2007 (dollars in millions):

	Six Months Ended
	June 30,
	2008			2007
Net cash flow provided by operating activities	$	679		$	290
Net cash flow used for investing activities		(379	)		(428	)
Net cash flow provided by (used for) financing activities		(259	)		74

     The increase of approximately $389 million in net cash provided by operating activities is primarily due to increased collateral and margin cash collected from counterparties as a result of changes in commodity prices; increased retail revenue related to higher Base Fuel Rates; and lower real estate investments as a result of the weak real estate market. These positive factors were partially offset by changes in working capital.

     The decrease of approximately $49 million in net cash used for investing activities is primarily due to a real estate commercial property sale in 2008, partially offset by lower cash proceeds from the sale of investment securities at APS and higher levels of capital expenditures (see table and discussion below).

     The increase of approximately $333 million in net cash used for financing activities is primarily due to lower levels of short-term debt as a result of higher cash from operations and lower levels of long-term debt as a result of the proceeds from the sale of a real estate commercial property in 2008.

Liquidity

     Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for the six months ended June 30, 2007 and 2008 and estimated capital expenditures, net of contributions in aid of construction, for the next three years:

51

CAPITAL EXPENDITURES
(dollars in millions)

	Six Months Ended				Estimated for the Year Ended
	June 30,				December 31,
	2007		2008		2008		2009		2010
APS Distribution	$	198	$	173	$	380	$	340	$	280
Generation (a)		85		164		380		390		380
Transmission		120		81		220		320		290
Other (b)		6		11		50		40		50
Subtotal		409		429		1,030		1,090		1,000
SunCor (c)		99		25		50		30		100
Other		1		6		20		20		10
Total	$	509	$	460	$	1,100	$	1,140	$	1,110

(a)	Generation includes nuclear fuel expenditures of approximately $90 million to $120 million per year for 2008, 2009 and 2010.
(b)	Primarily information systems and facilities projects.
(c)	Primarily capital expenditures for residential, land development and retail and office building construction reflected in “Expenditures for real estate investments” and “Capital expenditures” 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 facility costs. Examples of the types of projects included in the forecast include power lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems, partially offset by amounts for the recent changes in the line extension policy. See “Line Extension Schedule” in Note 3 of the 2007 Form 10-K for further details regarding the recent changes to the line extension policy.

     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants. 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 $70 million to $120 million per year for 2008, 2009 and 2010. We are also monitoring the status of certain environmental matters, which, depending on their final outcome, could require modification to our environmental expenditures. (See “Business of Arizona Public Service Company — Environmental Matters — Regional Haze Rules” in Item 1 of the 2007 Form 10-K and “Environmental Matters - Mercury” in Part II, Item 5 below.)

     In early 2008, we announced and began implementing a cost reduction effort that includes the elimination of approximately $200 million of capital expenditures for the years 2008-2012 and operations and maintenance expense reductions relating to staffing and other costs. These capital expenditure reductions, as they relate to the years 2008-2010, are included in the estimates provided above. In addition, we are pursuing a reduction of at least an additional $500 million in capital expenditures over the next three years, with implementation

52

beginning in late 2008, due to our reduced customer growth outlook (see “Pinnacle West Consolidated — Factors Affecting Our Financial Outlook — Customer and Sales Growth” below), deferral of several large transmission projects, and reduction in general plant capital expenditures. Since the review and analysis of this effort is still in progress, the capital expenditure estimates above do not yet include these reductions.

     Capital expenditures will be funded with internally generated cash and/or external financings, which may include issuances of long-term debt and Pinnacle West common stock.

     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, our outlook for future business prospects, payout ratio trends, free cash flow and financial market conditions.

     Our primary sources of cash are dividends from APS, external debt and equity 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 June 30, 2008, APS’ common equity ratio, as defined, was approximately 55%.

     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 plan asset performance and plan actuarial assumptions. We contributed approximately $52 million in 2007. The contribution to our pension plan in 2008 is estimated to be approximately $35 million. The expected contribution to our other postretirement benefit plans in 2008 is estimated to be approximately $20 million, of which $10 million has been contributed through August 2008. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

     On July 23, 2008, the Pinnacle West Board of Directors declared a quarterly dividend of $0.525 per share of common stock, payable on September 2, 2008, to shareholders of record on August 1, 2008.

     See “Equity Infusion Notice” in Note 5 for information regarding Pinnacle West’s filing of a notice with the ACC regarding a potential equity infusion into APS of up to $400 million.

     APS

     APS’ capital requirements consist primarily of capital expenditures and mandatory redemptions of long-term debt. APS pays for its capital requirements with cash from operations, equity infusions from Pinnacle West 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

53

for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

     Other Financing Matters —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 annual and, if necessary, periodic PSA adjustments. See “PSA Modifications” in Note 3, Item 8 of the 2007 Form 10-K for information regarding the PSA approved by the ACC.

     See “Cash Flow Hedges�� in Note 10 for information related to the change in our margin account.

     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 six months ended June 30, 2007 and 2008 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.

     APSES expects minimal capital expenditures over the next three years.

     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 June 30, 2008, the ratio was approximately 49% for Pinnacle West and 46% for APS. The provisions regarding interest coverage require minimum cash coverage of two times the interest requirements for APS. The interest coverage was approximately 5 times under APS’ bank financing agreements as of June 30, 2008. 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, our bank financial agreements contain a pricing grid in which the interest costs we pay are determined by our current credit ratings.

     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.

54

     See Note 4 for further discussions.

     Credit Ratings

     The ratings of securities of Pinnacle West and APS as of August 5, 2008 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, natural gas transportation, fuel supply, and other energy-related contracts.

	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Senior unsecured (a)	Baa3 (P)	BB+ (prelim)	N/A
Commercial paper	P-3	A-3	F3
Outlook	Stable	Stable	Negative
APS
Senior unsecured	Baa2	BBB-	BBB
Secured lease obligation bonds	Baa2	BBB-	BBB
Commercial paper	P-2	A-3	F3
Outlook	Stable	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 assigned a provisional (P) rating and Standard & Poor’s assigned a preliminary (prelim) rating to the senior unsecured securities that can be issued under such shelf registration.

     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 (see Note 9).

     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 June 30, 2008, APS would have been required to assume approximately $188 million of debt and pay the equity participants approximately $169 million.

55

     Guarantees and Letters of Credit

     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 and APS relate to commodity energy products. Our credit support instruments enable APSES to offer energy-related products and commodity energy. Non-performance or non-payment under the original contract by our subsidiaries would require performance under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s current outstanding guarantees on behalf of our subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. 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.

Contractual Obligations

     Our future contractual obligations related to fuel and purchased power contracts have increased from approximately $3.1 billion at December 31, 2007 to $8.2 billion at June 30, 2008 as follows (dollars in billions):

2008	2009–2010	2011–2012	Thereafter	Total
$0.6	$0.7	$0.7	$6.2	$8.2

     This increase is primarily due to contingent obligations related to renewable energy contracts, primarily the 280MW solar project described in “Portfolio Resources — Alternative Generation Sources” in Part I, Item 1 of the 2007 Form 10-K.

     See Note 4 for a list of payments due on total long-term debt and capitalized lease requirements.

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, 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 2007 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2007 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

     See Note 20 for a discussion of SFAS No. 157, “Fair Value Measurements,” which we adopted January 1, 2008.

     See Notes 10 and S-1 for discussions of FASB Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts” (FIN 39-1), which we adopted January 1, 2008.

56

     We adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” effective January 1, 2008. This guidance provides companies with an option to report selected financial assets and liabilities at fair value. We did not elect the fair value option for any of our financial assets or liabilities. Therefore, SFAS No. 159 did not have an impact on our financial statements.

     In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities.” This guidance requires enhanced disclosures about derivative instruments and hedging activities. The Statement is effective for us on January 1, 2009. We are currently evaluating this new guidance but do not expect it to have a material impact on our financial statements.

PINNACLE WEST CONSOLIDATED — FACTORS AFFECTING OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

     GeneralElectric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and, to a lesser extent, from competitive retail and wholesale power markets in the western United States. For the years 2005 through 2007, retail electric revenues comprised approximately 84% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer growth, variations in weather from period to period, customer mix, average usage per customer, electricity rates and tariffs and the recovery of PSA deferrals. Off-System Sales of excess generation output and purchased power are included in regulated electricity segment revenues and related fuel and purchased power because they are credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess economic generation or other energy resources and wholesale market conditions, including demand and prices.

     Rate ProceedingsOur cash flows and profitability are affected by the rates APS may charge and the timely recovery of costs through those rates. APS’ retail rates are regulated by the ACC and its wholesale electric rates (primarily for transmission) are regulated by the FERC. APS’ capital expenditure requirements, which are discussed above under “Liquidity and Capital Resources - - Capital Expenditure Requirements,” are substantial because of customer growth in APS’ service territory, inflationary impacts on the capital budget and increased generation, environmental and reliability costs, highlighting APS’ need for the timely recovery through rates of these and other expenditures. On March 24, 2008, and later updated on June 2, 2008, APS filed a rate case with the ACC requesting, among other things, an increase in rates to help defray rising infrastructure costs, approval of an impact fee and approval of new conservation rates. Details of the current ACC rate case, a request for an interim increase related to this rate case, and other retail and wholesale rate matters are discussed in Note 5.

     Fuel and Purchased Power CostsFuel and purchased power costs included on our Condensed Consolidated Statements of Income 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 “PSA Modifications” in Note 3, Item 8 of the 2007 Form 10-K for information regarding the PSA. APS’ recovery of PSA deferrals from its ratepayers is subject to annual and, if necessary, periodic PSA adjustments.

57

     Customer and Sales GrowthThe customer and sales growth referred to in this paragraph apply to Native Load customers and sales to them. Customer growth in APS’ service territory for the six-month period ended June 30, 2008 was 1.8% compared with the prior-year period. Customer growth averaged 4.0% a year for the three years 2005 through 2007; and we currently expect customer growth to decline, averaging about 1% per year for 2008 through 2010 due to factors reflecting the economic conditions both nationally and in Arizona. For the three years 2005 through 2007, APS’ actual retail electricity sales in kilowatt-hours grew at an average annual rate of 4.9%; adjusted to exclude the effects of weather variations, such retail sales growth averaged 4.0% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow about 1% on average per year during 2008 through 2010, excluding the effects of weather variations. We currently expect our retail sales growth in 2008 to be below average because of potential effects on customer usage from economic conditions and retail rate increases (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.

     WeatherIn 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 MarketOur 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. See “Rate Requests for Transmission and Ancillary Services” in Note 5 for information regarding APS’ filing with the FERC requesting an increase in transmission rates.

Other Factors Affecting Financial Results

     Operations and Maintenance ExpensesOperations and maintenance expenses are impacted by growth, power plant operations, maintenance of utility plant (including generation, transmission, and distribution facilities), inflation, outages, higher-trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization ExpensesDepreciation and amortization expenses are impacted by net additions to utility plant and other property (such as new generation, transmission, and distribution facilities), and changes in depreciation and amortization rates. See “Capital Expenditure Requirements” above for information regarding planned additions to our facilities.

     Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessment ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.3% of the assessed value for 2007 and 8.9% of assessed value for 2006. We expect property taxes to increase as we add new utility plant (including new generation, transmission and distribution facilities) and as we

58

improve our existing facilities. See “Capital Expenditure Requirements” above for information regarding planned additions to our facilities.

     Interest ExpenseInterest 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 CompetitionAlthough some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail electric service providers providing unbundled energy or other utility services to APS’ customers. We cannot predict when, and the extent to which, additional electric service providers will re-enter APS’ service territory.

     SubsidiariesSunCor’s net income was $24 million in 2007, $61 million in 2006 and $56 million in 2005. See Note 17 for further discussion. We currently expect minimal contributions from SunCor in 2008. This estimate reflects the weak real estate market.

     The historical results of APSES, Pinnacle West Marketing & Trading and El Dorado are not indicative of future performance.

     GeneralOur financial results may be affected by a number of broad factors. See “Forward-Looking Statements” below 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 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. 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. 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. 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.

59

     The following tables show the net pretax changes in mark-to-market value of our derivative positions for the six months ended June 30, 2008 and 2007 (dollars in millions):

	Six Months Ended
	June 30,
	2008			2007
Mark-to-market of net positions at beginning of period	$	40		$	15
Recognized in earnings:
Change in mark-to-market gains for future period deliveries		32			19
Mark-to-market gains realized including ineffectiveness during the period		(3	)		(21	)
Decrease in regulatory asset		178			34
Recognized in OCI:
Change in mark-to-market gains for future period deliveries (a)		361			30
Mark-to-market gains realized during the period		(39	)		(18	)
Change in valuation techniques		—			—
Mark-to-market of net positions at end of period	$	569		$	59

(a) The increase is primarily due to increases in forward natural gas prices.

     The table below shows the net fair value of maturities of our derivative contracts (dollars in millions) at June 30, 2008 by yearly 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 2007 Form 10-K and Note 20 for more discussion of our valuation methods.

														Years		Total
Source of Fair Value	2008			2009			2010			2011		2012		thereafter		fair value
Level 1 — Quoted prices in active markets	$	118		$	54		$	2		$	—	$	—	$	—	$	174
Level 2 — Significant other observable inputs		82			167			101			38		—		—		388
Level 3 — Significant unobservable inputs		(5	)		(5	)		(2	)		1		9		9		7
Total by maturity	$	195		$	216		$	101		$	39	$	9	$	9	$	569

60

     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 June 30, 2008 and December 31, 2007 (dollars in millions):

	June 30, 2008						December 31, 2007
	Gain (Loss)						Gain (Loss)
				Price Down					Price Down
	Price Up 10%			10%			Price Up 10%		10%
Mark-to-market changes reported in:
Earnings
Electricity	$	(9	)	$	9		$	3	$	(3	)
Natural gas		19			(19	)		4		(4	)
Regulatory asset (liability) or OCI (a)
Electricity		45			(45	)		45		(45	)
Natural gas		131			(131	)		85		(85	)
Total	$	186		$	(186	)	$	137	$	(137	)

(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. To the extent the amounts are eligible for inclusion in the PSA, the amounts are recorded as either a regulatory asset or liability.

Credit Risk

     We are exposed to losses in the event of non-performance or non-payment by counterparties. See Note 1, “Derivative Accounting” in Item 8 of our 2007 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.

61

ARIZONA PUBLIC SERVICE COMPANY — RESULTS OF OPERATIONS

Operating Results — Three-month period ended June 30, 2008 compared with three-month period ended June 30, 2007

     Our consolidated net income for the three months ended June 30, 2008 was $125 million compared with net income of $75 million for the comparable prior-year period. Net income increased approximately $50 million due to various factors, including income tax benefits of $29 million related to prior years resolved in 2008; the impacts of retail and transmission rate increases; increased mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals; a regulatory disallowance in 2007; increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts; and higher retail sales primarily due to customer growth. These positive factors were partially offset by the effects of milder weather on retail sales; higher operations and maintenance expense primarily related to distribution system reliability, generation costs (including planned maintenance and overhauls), and other costs; and higher depreciation and amortization primarily due to higher plant balances.

     Additional details on the major factors that increased (decreased) net income for the three-month period ended June 30, 2008 compared with the prior-year period are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Impacts of retail rate increase effective July 1, 2007 and transmission rate increase effective March 1, 2008:
Retail revenue increase primarily related to higher Base Fuel Rate	$	93		$	57
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(76	)		(46	)
Transmission rate increase (including a retail rate component)		7			4
Higher mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		17			10
Regulatory disallowance in 2007		14			8
Increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts		7			4
Higher retail sales primarily due to customer growth, excluding weather effects		6			4
Effects of milder weather on retail sales		(18	)		(11	)
Higher operations and maintenance expense primarily related to distribution system reliability, increased generation costs (including planned maintenance and overhauls), and other costs		(12	)		(7	)
Higher depreciation and amortization primarily due to higher plant balances		(5	)		(3	)
Income tax benefits related to prior years resolved in 2008		—			29
Miscellaneous items, net		(6	)		1
Increase in net income	$	27		$	50

62

     Electric operating revenues were $109 million higher for the three months ended June 30, 2008 compared with the prior-year period primarily because of:

• a $93 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $20 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $13 million increase in revenues related to long-term traditional wholesale contracts;

• an $8 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $7 million increase due to a transmission rate increase (including a retail rate component) effective March 1, 2008;

• a $24 million decrease in retail revenue due to the effects of milder weather; and

• an $8 million decrease 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.

Operating Results — Six-month period ended June 30, 2008 compared with six-month period ended June 30, 2007

     Our net income for the six months ended June 30, 2008 was $119 million compared with net income of $79 million for the comparable prior-year period. Net income increased approximately $40 million due to various factors, including income tax benefits of $29 million related to prior years resolved in 2008; the impacts of retail and transmission rate increases; increased mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals; a regulatory disallowance in 2007; higher retail sales primarily due to customer growth; and increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts. These positive factors were partially offset by higher operations and maintenance expense primarily related to increased generation costs, (including planned maintenance and overhauls), increased costs related to distribution system reliability and other costs; the effects of milder weather on retail sales; and higher depreciation and amortization primarily due to higher plant balances.

     Additional details on the major factors that increased (decreased) net income for the six-month period ended June 30, 2008 compared with the prior-year period are contained in the following table (dollars in millions):

63

	Increase (Decrease)
	Pretax			After Tax
Impacts of retail rate increase effective July 1, 2007 and transmission rate increase effective March 1, 2008:
Retail revenue increase primarily related to higher Base Fuel Rate	$	156		$	95
Decreased deferred fuel and purchased power costs related to higher Base Fuel Rate		(141	)		(86	)
Transmission rate increase (including a retail rate component)		10			6
Higher mark-to-market valuations of fuel and purchased power contracts related to changes in market prices, net of related PSA deferrals		26			16
Regulatory disallowance in 2007		14			8
Higher retail sales primarily due to customer growth, excluding weather effects		12			7
Increased revenues, net of fuel and purchased power costs, related to long-term traditional wholesale contracts		11			7
Effects of milder weather on retail sales		(19	)		(12	)
Operations and maintenance expense increases primarily due to:
Increased customer service and other costs as a result of distribution system reliability		(18	)		(11	)
Increased generation costs, including more planned maintenance and overhauls		(15	)		(9	)
Higher depreciation and amortization primarily due to higher plant balances		(11	)		(7	)
Income tax benefits related to prior years resolved in 2008		—			29
Miscellaneous items, net		(7	)		(3	)
Increase in net income	$	18		$	40

     Electric operating revenues were $197 million higher for the six months ended June 30, 2008 compared with the prior-year period primarily because of:

• a $156 million increase in retail revenues due to a rate increase effective July 1, 2007;

• a $37 million increase in revenues from Off-System Sales due to higher prices and volumes;

• a $20 million increase in revenues related to long-term traditional wholesale contracts;

• a $16 million increase in retail revenues primarily related to customer growth, excluding weather effects;

• a $10 million increase due to a transmission rate increase (including a retail rate component) effective March 1, 2008;

• a $26 million decrease 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;

64

• a $25 million decrease in retail revenue due to the effects of milder weather; and

• a $9 million net increase due to miscellaneous factors.

ARIZONA PUBLIC SERVICE COMPANY — LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

     The following table presents net cash provided by (used for) operating, investing and financing activities for the six months ended June 30, 2008 and 2007 (dollars in millions):

	Six Months Ended
	June 30,
	2008			2007
Net cash flow provided by operating activities	$	686		$	334
Net cash flow used for investing activities		(457	)		(396	)
Net cash flow used for financing activities		(196	)		(18	)

     The increase of approximately $352 million in net cash provided by operating activities is primarily due to increased collateral and margin cash collected from counterparties as a result of changes in commodity prices and increased retail revenue related to higher Base Fuel Rates. These positive factors were partially offset by changes in working capital.

     The increase of approximately $61 million in net cash used for investing activities is primarily due to lower cash proceeds from the sale of investment securities at APS and higher levels of capital expenditures (see table and discussion above).

     The increase of approximately $178 million in net cash used for financing activities is primarily due to lower levels of short-term debt as a result of higher cash from operations.

     Contractual Obligations

     APS’ future contractual obligations related to fuel and purchased power contracts have increased from approximately $3.0 billion at December 31, 2007 to $8.1 billion at June 30, 2008 as follows (dollars in billions):

2008	2009–2010	2011–2012	Thereafter	Total
$0.6	$0.7	$0.6	$6.2	$8.1

     This increase is primarily due to contingent obligations related to renewable energy contracts, primarily the 280MW solar project described in “Portfolio Resources – Alternative Generation Sources” in Part I, Item 1 of the 2007 Form 10-K.

     See Note 4 for a list of APS’ payments due on total long-term debt and capitalized lease requirements.

65

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 2007 Form 10-K, these factors include, but are not limited to:

• state and federal regulatory and legislative decisions and actions, including the outcome or timing of our pending rate cases;

• the outcome of regulatory, legislative and judicial proceedings, both current and future, including those related to environmental matters and climate change;

• our ability to reduce capital expenditures and other costs while maintaining reliability and customer service levels, and unexpected developments that would limit us from achieving all or some of our planned capital expenditure reductions;

• the potential for additional restructuring of the electric industry, including decisions impacting wholesale competition and the introduction of retail electric competition in Arizona;

• fluctuations in market prices for electricity, natural gas, coal, uranium and other fuels used in our generating facilities, and supplies of such commodities;

• volatile market liquidity, 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);

• power plant performance and outages;

• transmission outages and constraints;

• weather variations affecting local and regional customer energy usage;

• customer growth and energy usage;

• national and regional economic and market conditions, including the strength of the housing and credit markets, volatile fuel and purchased power costs, the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies, and the results of litigation and other proceedings resulting from the California and Pacific Northwest energy situations;

• ability of power plant participants to meet contractual or other obligations;

• the cost of debt and equity capital and access to capital markets;

• current credit ratings remaining in effect for any given period of time;

• 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 trusts, 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;

66

• 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.

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, as amended (the “Exchange Act”) (15 U.S.C. 78aet 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 Principal Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of June 30, 2008. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Principal 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 Principal Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of June 30, 2008. Based on that evaluation, APS’ Chief Executive Officer and Principal 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 June 30, 2008 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

67

Part II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

     See Note 12 in regard to pending or threatened litigation or other disputes. See also “Superfund” under Item 5 below.

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 2007 Form 10-K, which could materially affect the business, financial condition, cash flows or future results of APS and Pinnacle West. The risks described in the 2007 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, cash flows and/or operating results of APS and Pinnacle West.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Proposal 1 — Election of Directors

     At our Annual Meeting of Shareholders held on May 21, 2008, the following persons were elected as directors:

Directors (Term to expire at			Abstentions and Broker
2009 Annual Meeting)	Votes For	Votes Withheld	Non-Votes
Edward N. Basha, Jr.	83,924,952	2,108,316	N/A
Susan Clark-Johnson	83,949,841	2,083,427	N/A
Michael L. Gallagher	76,015,352	10,017,916	N/A
Pamela Grant	83,785,638	2,247,630	N/A
Roy A. Herberger, Jr.	83,806,434	2,226,834	N/A
William S. Jamieson	83,795,031	2,238,237	N/A
Humberto S. Lopez	83,802,444	2,230,824	N/A
Kathryn L. Munro	84,037,198	1,996,070	N/A
Bruce J. Nordstrom	84,035,321	1,997,947	N/A
W. Douglas Parker	83,646,676	2,386,592	N/A
William J. Post	83,850,519	2,182,749	N/A
William L. Stewart	83,906,592	2,126,676	N/A

68

Proposal 2 — Amend the Articles of Incorporation to Provide for Majority Shareholder Vote to Approve Certain Actions

     At the same meeting, a Company proposal requesting that the Articles of Incorporation be amended to eliminate the two-thirds voting requirement for certain actions was submitted to the shareholders, and the voting was as follows:

Company proposal to provide for
majority shareholder vote to
approve certain actions including
amending the Articles of			Abstentions and
Incorporation	Votes For	Votes Against	Broker Non-Votes
	82,536,970	1,766,992	1,729,305

Proposal 3 — Independent Auditors

     At the same meeting, a proposal for the ratification of the selection of Deloitte & Touche LLP as independent auditors of the Company for the fiscal year ending 2008 was submitted to the shareholders, and the voting was as follows:

Proposal for the ratification
of the selection of Deloitte &
Touche LLP for the fiscal year			Abstentions and
ending 2008	Votes For	Votes Against	Broker Non-Votes
	84,637,340	1,190,613	205,315

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

     Superfund

     See “Superfund” in Note 12 for a discussion of a Superfund site.

     By letter dated April 25, 2008, the EPA informed APS that it may be a PRP in the Gila River Indian Reservation Superfund Site in Maricopa County, Arizona. APS, along with three other electric utility companies, owns a parcel of property on which a transmission pole and a portion of a transmission line are located. The property abuts the Gila River Indian Community boundary and, at one time, may

69

have been part of an airfield where crop dusting took place. Currently, the EPA is only seeking payment from APS and four other PRPs for past cleanup-related costs involving contamination from the crop dusting. Based upon the total amount of cleanup costs reported by the EPA in its letter to APS, we do not expect that the resolution of this matter will have a material adverse impact on our financial position, results of operations, or cash flows.

     Mercury

     On March 15, 2005, the EPA issued the Clean Air Mercury Rule (CAMR) to control mercury emissions from coal-fired power plants.  This rule established performance standards limiting mercury emissions from coal-fired power plants and established a two phased market-based emissions trading program.  Under the trading program, the EPA assigned each state a mercury emissions “budget” and each state was required to submit to the EPA a plan detailing how it will meet its “budget.”

     In November 2006, ADEQ submitted a State Implementation Plan (“SIP”) to the EPA to implement the CAMR.  ADEQ’s SIP generally incorporated the EPA’s model cap-and-trade program, but it included additional requirements, including the requirement to meet a 90% mercury removal control level or 0.0087 lbs/GWh, whichever is greater, the requirement to obtain mercury allowances at a 2:1 ratio for any emissions that fall below the specified control level, and the requirement, beginning in 2013, to consider clean coal technologies as part of permitting any new generation.

     On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit vacated the CAMR and the EPA rule that allowed for the creation of the CAMR and, on March 14, 2008, the court issued the mandate to vacate these rules.  On May 20, 2008, the D.C. Circuit denied EPA’s request to reconsider its decision.   EPA is now considering an appeal to the Supreme Court. Unless and until this decision is overturned, the law in effect prior to the adoption of the CAMR becomes the applicable law, and requires the EPA to develop an emission limit for mercury that represents the maximum achievable control technology (“MACT”).  It is expected to take the EPA several years to establish such a standard, followed by a period of several years during which existing plants would implement any controls needed to comply with the standard.

     The court’s ruling also invalidates CAMR-based portions of ADEQ’s mercury rule (the trading provisions of the rule), although the state-only emission limits remain in effect.  On July 25, 2008, the Arizona Utilities Group (comprised of APS, Arizona Electric Power Cooperative, Salt River Project, Tucson Electric Power Company, and Tri-State Generation and Transmission Association) filed with ADEQ a Petition for Reconsideration and Repeal of the state mercury rule. The petition asserts that ADEQ does not have statutory authority to administer and enforce the state mercury rule, in light of the vacatur of the CAMR and the requirement that EPA promulgate a MACT standard.

     While we continue to monitor this matter, we cannot predict the final outcome of the court’s proceeding (if an appeal is filed), the response of ADEQ to the court’s decision or to the petition, or the scope, timing or impact of any alternate rules that may be enacted to address mercury emissions.

     We have installed, and continue to install, certain of the equipment necessary to meet the current mercury standards.  However, due to the recent U.S. Court of Appeals decision described above, we will monitor the type and timing of any necessary equipment installation.  The estimated costs expected to be incurred over the next three years for such equipment are included in our environmental expenditure estimates (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Expenditures” in Part I, Item 2).

70

Item 6. EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
3.1	Pinnacle West	Articles of Incorporation, restated as of May 21, 2008
10.1a	Pinnacle West APS	Letter Agreement dated June 17, 2008 between Pinnacle West/APS and James R. Hatfield
10.2a	Pinnacle West	Description of Annual Stock Grants to Non-Employee Directors
10.3a	APS	Letter Agreement dated July 22, 2008 between APS and Randall K. Edington
10.4ab	Pinnacle West	Form of Restricted Stock Agreement Under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.5ab	Pinnacle West	Form of Performance Share Agreement Under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.6ab	Pinnacle West	Form of Restricted Stock Unit Agreement Under the Pinnacle West Capital Corporation 2007 Long-Term Incentive Plan
10.7a	APS	Description of 2008 Palo Verde Specific Compensation Opportunity for Randall K. Edington
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

a	Management contract or compensatory plan or arrangement filed as an exhibit pursuant to Item 6 of Form 10-Q.
b	Additional agreements, substantially identical in all material respects to this Exhibit, have been entered into with additional persons. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.

71

Exhibit No.	Registrant(s)	Description
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, President and Principal 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 Donald E. Brandt, President, Chief Executive Officer and Principal 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, President and Principal Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer, President and Principal Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

72

     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			Previously Filed as	Date
No.	Registrant(s)	Description	Exhibit1	Filed
3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of May 23, 2007	4.2 to Pinnacle West/APS May 23, 2007 Form 8-K Report, File Nos. 1-8962 and 1-4473	5-25-07
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

¹ 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.

73

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: August 7, 2008	By:	/s/  Donald E. Brandt
		Donald E. Brandt
		President and Chief Operating Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)
	ARIZONA PUBLIC SERVICE COMPANY      (Registrant)
Dated: August 7, 2008	By:	/s/  Donald E. Brandt
		Donald E. Brandt
		President and Chief Executive Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)

74