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 September 30, 2005

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. Yes þ No o

     Indicate by check mark whether each registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

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

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

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

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

PINNACLE WEST CAPITAL CORPORATION	Number of shares of common stock, no par value, outstanding as of November 7, 2005: 99,000,520
ARIZONA PUBLIC SERVICE COMPANY	Number of shares of common stock, $2.50 par value, outstanding as of November 7, 2005: 71,264,947

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

     This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant. 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
Item 1.	Financial Statements
	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		70
Item 4.	Controls and Procedures		71
Part II
Item 1.	Legal Proceedings		72
Item 5.	Other Information		72
Item 6.	Exhibits		73
Signatures			75
Exhibit 12.1
Exhibit 12.2
Exhibit 31.1
Exhibit 31.2
Exhibit 31.3
Exhibit 31.4
Exhibit 32.1
Exhibit 32.2
Exhibit 99.1
Exhibit 99.2
Exhibit 99.3
Exhibit 99.4

GLOSSARY

ACC — Arizona Corporation Commission

ADEQ — Arizona Department of Environmental Quality

ALJ — Administrative Law Judge

APS — Arizona Public Service Company, a subsidiary of the Company

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

CC&N — Certificate of Convenience and Necessity

Clean Air Act — Clean Air Act, as amended

Company — Pinnacle West Capital Corporation

DOE — United States Department of Energy

EITF — FASB’s Emerging Issues Task Force

El Dorado — El Dorado Investment Company, a subsidiary of the Company

EPA — United States Environmental Protection Agency

ERMC — Energy Risk Management Committee

FASB — Financial Accounting Standards Board

FERC — United States Federal Energy Regulatory Commission

FIN — FASB Interpretation

Financing Order — ACC Order that authorized APS’ $500 million loan to Pinnacle West Energy in May 2003

GAAP — accounting principles generally accepted in the United States of America

GenWest — GenWest, LLC, a wholly-owned subsidiary of Pinnacle West Energy

IRS — United States Internal Revenue Service

kWh — kilowatt-hour

Moody’s — Moody’s Investors Service

MW — megawatt, one million watts

MWh — megawatt-hours, one million watts per hour

NAC — collectively, NAC Holding Inc. and NAC International Inc., subsidiaries of El Dorado that were sold in November 2004

Native Load — retail and wholesale sales supplied under traditional cost-based rate regulation

NPC — Nevada Power Company

NPUC — Nevada Public Utilities Commission

NRC — United States Nuclear Regulatory Commission

Nuclear Waste Act — Nuclear Waste Policy Act of 1982, as amended

OCI — other comprehensive income

2

Off-System Sales — sales of electricity from generation owned 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

PPL Sundance — PPL Sundance Energy, LLC

PRP — potentially responsible party

PSA — power supply adjustor

PWEC Dedicated Assets — the following power plants, each of which was transferred by Pinnacle West Energy to APS on July 29, 2005: Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3

PX — California Power Exchange

Retail Fuel and Power Costs — fuel and purchased power costs eligible to be deferred under the PSA

RFP — request for proposals

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

SEC — United States Securities and Exchange Commission

SFAS — Statement of Financial Accounting Standards

Silverhawk — Silverhawk Power Station, a 570-megawatt, natural gas-fueled, combined-cycle electric generating facility located 20 miles north of Las Vegas, Nevada

Standard & Poor’s — Standard & Poor’s Corporation

SunCor — SunCor Development Company, a subsidiary of the Company

Sundance Plant — 450-megawatt generating facility located approximately 55 miles southeast of Phoenix, Arizona

Superfund — Comprehensive Environmental Response, Compensation and Liability Act

T&D — transmission and distribution

Track B Order — ACC order dated March 14, 2003 regarding competitive solicitation requirements for power purchases by Arizona’s investor-owned electric utilities

Trading — energy-related activities entered into with the objective of generating profits on changes in market prices

2004 Settlement Agreement — an agreement settling APS’ 2003 rate case

2004 Form 10-K — Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2004

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
	September 30,
	2005			2004
OPERATING REVENUES
Regulated electricity segment	$	753,428		$	670,559
Marketing and trading segment		107,031			91,267
Real estate segment		78,755			72,754
Other revenues		16,369			12,585
Total		955,583			847,165
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		203,519			202,156
Marketing and trading segment fuel and purchased power		86,945			76,684
Operations and maintenance		158,940			158,607
Real estate operations segment		65,880			66,414
Depreciation and amortization		87,123			93,360
Taxes other than income taxes		34,325			31,020
Other expenses		13,521			9,568
Regulatory disallowance (Note 5)		143,217			—
Total		793,470			637,809
OPERATING INCOME		162,113			209,356
OTHER
Allowance for equity funds used during construction		2,852			(1,327	)
Other income (Note 14)		8,694			2,786
Other expense (Note 14)		(4,915	)		(5,094	)
Total		6,631			(3,635	)
INTEREST EXPENSE
Interest charges		47,046			46,715
Capitalized interest		(3,301	)		(4,506	)
Total		43,745			42,209
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		124,999			163,512
INCOME TAXES		40,305			59,183
INCOME FROM CONTINUING OPERATIONS		84,694			104,329
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $12,407 and $890 (Note 17)		19,043			1,071
NET INCOME	$	103,737		$	105,400
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		98,697			91,357
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		98,816			91,491
EARNINGS PER WEIGHTED — AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations — basic	$	0.86		$	1.14
Net income — basic		1.05			1.15
Income from continuing operations — diluted		0.86			1.14
Net income — diluted		1.05			1.15
DIVIDENDS DECLARED PER SHARE	$	0.475		$	0.45

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)

	Nine Months Ended
	September 30,
	2005			2004
OPERATING REVENUES
Regulated electricity segment	$	1,749,110		$	1,605,952
Marketing and trading segment		267,460			290,107
Real estate segment		232,950			186,762
Other revenues		46,763			32,904
Total		2,296,283			2,115,725
OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		442,532			442,409
Marketing and trading segment fuel and purchased power		215,347			232,516
Operations and maintenance		467,121			434,588
Real estate operations segment		190,555			175,560
Depreciation and amortization		262,030			294,942
Taxes other than income taxes		103,528			93,658
Other expenses		39,451			25,893
Regulatory disallowance (Note 5)		143,217			—
Total		1,863,781			1,699,566
OPERATING INCOME		432,502			416,159
OTHER
Allowance for equity funds used during construction		8,407			2,859
Other income (Note 14)		18,019			49,980
Other expense (Note 14)		(12,985	)		(14,274	)
Total		13,441			38,565
INTEREST EXPENSE
Interest charges		142,820			135,064
Capitalized interest		(10,134	)		(8,686	)
Total		132,686			126,378
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		313,257			328,346
INCOME TAXES		113,863			119,476
INCOME FROM CONTINUING OPERATIONS		199,394			208,870
INCOME (LOSS) FROM DISCONTINUED OPERATIONS
Net of income tax expense (benefit) of $(28,586) and $707 (Note 17)		(44,474	)		596
NET INCOME	$	154,920		$	209,466
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — BASIC		95,642			91,322
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING — DILUTED		95,755			91,430
EARNINGS PER WEIGHTED — AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations — basic	$	2.08		$	2.29
Net income — basic		1.62			2.29
Income from continuing operations — diluted		2.08			2.28
Net income — diluted		1.62			2.29
DIVIDENDS DECLARED PER SHARE	$	1.425		$	1.35

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

5

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

	September 30,			December 31,
	2005			2004
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	871,253		$	163,366
Investments in debt securities		68,721			181,175
Customer and other receivables		585,082			461,090
Allowance for doubtful accounts		(5,130	)		(4,896	)
Materials and supplies (at average cost)		106,427			101,333
Fossil fuel (at average cost)		25,458			20,512
Assets from risk management and trading activities (Note 10)		955,754			166,896
Assets held for sale (Note 17)		203,982			—
Other current assets		81,404			47,654
Total current assets		2,892,951			1,137,130
INVESTMENTS AND OTHER ASSETS
Real estate investments — net		356,155			382,398
Assets from long-term risk management and trading activities (Note 10)		544,698			224,341
Decommissioning trust accounts		290,537			267,700
Other assets		106,895			107,212
Total investments and other assets		1,298,285			981,651
PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		10,591,897			10,486,648
Less accumulated depreciation and amortization		3,615,992			3,365,954
Total		6,975,905			7,120,694
Construction work in progress		339,492			258,119
Intangible assets, net of accumulated amortization		108,862			105,486
Nuclear fuel, net of accumulated amortization		59,889			51,188
Net property, plant and equipment		7,484,148			7,535,487
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		142,806			—
Other regulatory assets		145,592			135,051
Other deferred debits		104,393			107,428
Total deferred debits		392,791			242,479
TOTAL ASSETS	$	12,068,175		$	9,896,747

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

6

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

	September 30,			December 31,
	2005			2004
LIABILITIES AND COMMON STOCK EQUITY
CURRENT LIABILITIES
Accounts payable	$	381,331		$	373,526
Accrued taxes		383,464			245,611
Accrued interest		52,075			38,795
Short-term borrowings		59,725			71,030
Current maturities of long-term debt		799,657			617,165
Customer deposits		59,173			55,558
Deferred income taxes		9,057			9,057
Liabilities from risk management and trading activities (Note 10)		801,597			113,406
Other current liabilities		336,428			101,748
Total current liabilities		2,882,507			1,625,896
LONG-TERM DEBT LESS CURRENT MATURITIES		2,569,449			2,584,985
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,358,414			1,227,553
Regulatory liabilities		569,863			506,646
Liability for asset retirements		263,457			251,612
Pension liability		227,168			234,445
Liabilities from long term risk management and trading activities (Note 10)		238,302			156,262
Unamortized gain — sale of utility plant		46,901			50,333
Other		371,607			308,819
Total deferred credits and other		3,075,712			2,735,670
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13 and 15)
COMMON STOCK EQUITY
Common stock, no par value		2,057,927			1,769,047
Treasury stock		(938	)		(428	)
Total common stock		2,056,989			1,768,619
Accumulated other comprehensive income (loss) (Note 11):
Minimum pension liability adjustment		(81,788	)		(81,788	)
Derivative instruments		343,498			59,243
Total accumulated other comprehensive income (loss)		261,710			(22,545	)
Retained earnings		1,221,808			1,204,122
Total common stock equity		3,540,507			2,950,196
TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	12,068,175		$	9,896,747

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)

	Nine Months Ended
	September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income	$	154,920		$	209,466
Adjustment to reconcile net income to net cash provided by operating activities:
Silverhawk impairment loss		91,057			—
Regulatory disallowance		143,217			—
Equity earnings in Phoenix Suns partnership		—			(34,594	)
Depreciation and amortization including nuclear fuel		292,190			326,780
Deferred fuel and purchased power		(142,806	)		—
Allowance for equity funds used during construction		(8,407	)		(2,859	)
Deferred income taxes		(51,045	)		32,558
Change in mark-to-market valuations		(29,785	)		(25,563	)
Changes in current assets and liabilities:
Customer and other receivables		(126,450	)		(106,538	)
Materials, supplies and fossil fuel		(15,581	)		2,631
Other current assets		(33,750	)		32,055
Accounts payable		7,505			32,634
Accrued taxes		137,853			101,640
Other current liabilities		251,575			24,898
Proceeds from the sale of real estate assets		15,020			52,378
Real estate investments		(59,527	)		(54,722	)
Change in risk management and trading-assets		16,092			7,257
Change in risk management and trading-liabilities		171,841			21,078
Change in other long-term assets		(17,001	)		(33,078	)
Change in other long-term liabilities		90,091			46,496
Net cash flow provided by operating activities		887,009			632,517
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(471,274	)		(356,707	)
Purchase of Sundance Plant		(185,046	)		—
Proceeds from the sale of 25% of Silverhawk		—			90,967
Capitalized interest		(10,134	)		(13,537	)
Purchases of investment securities		(2,567,237	)		(686,195	)
Proceeds from sale of investment securities		2,679,691			531,890
Proceeds from real estate investments		82,671			6,461
Proceeds from sale of the Phoenix Suns partnership		—			23,101
Other		(13,106	)		(8,775	)
Net cash flow used for investing activities		(484,435	)		(412,795	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		911,815			476,293
Short-term borrowings and payments — net		(19,975	)		8,123
Dividends paid on common stock		(137,234	)		(123,285	)
Repayment of long-term debt		(734,163	)		(604,989	)
Common stock equity issuance		290,542			—
Other		(5,672	)		14,116
Net cash flow provided by (used for) financing activities		305,313			(229,742	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		707,887			(10,020	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		163,366			136,929
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	871,253		$	126,909
Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	52,433		$	16,557
Interest paid, net of amounts capitalized	$	155,454		$	146,903

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 condensed consolidated financial statements include the accounts of Pinnacle West and our wholly-owned subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor and El Dorado. All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to the current year presentation.

2. Condensed Consolidated Financial Statements

     Our unaudited condensed consolidated financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position, results of operations and cash flows for the periods presented. We suggest that these condensed consolidated financial statements and notes to condensed consolidated financial statements be read along with the consolidated financial statements and notes to consolidated financial statements included in our 2004 Form 10-K.

3. Quarterly Fluctuations

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

4. Changes in Liquidity

     On January 15, 2005, APS repaid its $100 million 6.25% Notes due 2005. APS used cash on hand to repay these notes.

     On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Consolidated Balance Sheets.

     On April 11, 2005, Pinnacle West Energy issued $500 million of Floating Rate Senior Notes due April 1, 2007 and the notes were unconditionally guaranteed by Pinnacle West. Pinnacle West Energy used the proceeds of this issuance to repay a $500 million loan from APS. See “ACC Financing Order” in Note 5. On October 3, 2005, Pinnacle West Energy repaid the Floating Rate Senior Notes with $500 million received from APS in connection with the transfer of the PWEC Dedicated Assets. See “APS 2003 Rate Case” in Note 5 for information regarding APS’ acquisition of the PWEC Dedicated Assets.

9

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     On May 2, 2005, Pinnacle West redeemed at par all of its $165 million Floating Rate Senior Notes due November 1, 2005. Pinnacle West used cash on hand to redeem the notes.

     On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used such funds to pay a portion of the approximately $190 million purchase price to acquire the Sundance Plant and for other capital expenditures incurred to meet the growing needs of APS’ service territory.

     On August 1, 2005, APS repaid $300 million of its 7.625% Notes due 2005. APS used cash on hand to repay these notes.

     On August 22, 2005, APS issued $250 million of 5.50% Notes due 2035. A portion of the net proceeds from the sale of the notes was used for general corporate purposes and, on October 3, 2005, APS used the balance of the proceeds, along with cash on hand, to fund the $500 million that it was obligated to transfer to Pinnacle West Energy in connection with APS’ acquisition of the PWEC Dedicated Assets.

     APS had $566 million of pollution control bonds outstanding under which interest rates are reset on a daily or weekly basis as of September 30, 2005. The holders of $223 million of these bonds have the right to cause APS to purchase their bonds on the applicable reset date if the bonds are not remarketed. All $223 million of these bonds are classified as long-term debt because APS has the intent and ability, as demonstrated by credit agreements in place that extend for more than one year, to refinance any bonds that APS is required to purchase.

     The following is a list of principal payments due on Pinnacle West’s consolidated long-term debt and capitalized lease requirements as of September 30, 2005:

• $501 million in 2005;

• $384 million in 2006;

• $28 million in 2007;

• $6 million in 2008;

• $1 million in 2009; and

• $2.458 billion thereafter.

     We have investments in auction rate securities in which interest rates are reset on a short-term basis; however, the underlying contract maturity dates extend beyond three months. We classify the investments in auction rate securities as investments in debt securities on our Condensed Consolidated Balance Sheets. The purchase and sale activities related to these investments have been reclassified on the Condensed Consolidated Statements of Cash Flows for the prior-year period to show purchases and sales on a gross basis.

10

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

5. Regulatory Matters

Electric Industry Restructuring

State

     APS 2005 General Rate Case

     On November 4, 2005, APS filed a request with the ACC for a $409.1 million, or 19.9%, increase in its annual retail electricity revenues effective no later than December 31, 2006. The filing is based on a historical test year ended December 31, 2004, adjusted for known and measurable changes. APS expects the ACC to issue a procedural schedule during the next several months detailing the timeline for addressing the request.

     The requested rate increase is necessary to recover the following increased costs (dollars in millions):

	Annual Revenue
	Increase			Percent Increase
Increased fuel and purchased power costs(a)	$	246.8			12.0	%
Capital structure update		96.8			4.7
Rate base update, including acquisition of the Sundance Plant		42.5			2.1
Pension funding		41.2			2.0
Other items		(18.2	)		(0.9	)
Total increase	$	409.1			19.9	%

(a) a base rate for fuel and purchased power costs (“Retail Fuel and Power Costs”) of $0.030242 per kWh based on estimated 2006 prices.

11

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     APS has requested the following modifications related to the PSA approved by the ACC earlier this year (see “APS 2003 Rate Case” below):

• The $0.004 per kWh maximum adjustor rate over the life of the PSA would be eliminated, while the $0.004 per kWh maximum annual change in the adjustor rate would remain in effect;

• The $776.2 million annual limit on the Retail Fuel and Power Costs under APS’ current base rates and the PSA would be removed or increased;

• The current provision that APS is required to file a surcharge application with the ACC after accumulated pretax PSA deferrals equal $50 million and before they equal $100 million would be eliminated, thereby giving APS flexibility in determining when a surcharge filing should be made;

• The costs of renewable energy and capacity costs attributable to purchased power obtained through competitive procurement would be excluded from the existing 90/10 sharing arrangement under which APS absorbs 10% of the Retail Fuel and Power Costs above the base fuel amount and retains 10% of the benefit from Retail Fuel and Power Costs that are below the base fuel amount; and

• 10% of any realized gains or losses resulting from APS’ hedges of Retail Fuel and Power Costs would be retained or absorbed by APS before being subject to the 90/10 sharing provision under the PSA.

     This request does not include the 1.7% PSA surcharge filing presently under consideration by the ACC, nor an expected spring 2006 adjustor filing of approximately 5% as prescribed by the existing PSA order. We currently estimate that approximately 40% of this 5% adjustor request (or a 2% increase) will be to recover unplanned 2005 Palo Verde outage costs which were necessary to operate Palo Verde prudently. APS estimates that the additional replacement power cost associated with the unplanned outages at Palo Verde through October 31, 2005, for which APS would be seeking recovery, were approximately $40 million before income taxes.

     APS 2003 Rate Case

     On April 7, 2005, the ACC issued an order in the general rate case that APS filed on June 27, 2003. In its order, the ACC approved the 2004 Settlement Agreement, with certain revisions. Certain key financial components of the order include:

• APS received an annual retail rate increase of approximately 4.2%, which was effective as of April 1, 2005. This increase does not include the impact of the PSA (discussed below).

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• The PSA provides for the annual adjustment of rates to reflect variations in fuel and purchased power costs, subject to specified parameters and procedures, including the following:

• APS will record deferrals for recovery or refund to the extent actual Retail Fuel and Power Costs vary from $0.020743 per kWh (base fuel amount);

• the above deferrals are subject to a 90/10 sharing arrangement in which APS must absorb 10% of the Retail Fuel and Power Costs above the base fuel amount and may retain 10% of the benefit from the Retail Fuel and Power Costs that are below the base fuel amount;

• amounts to be recovered or refunded through the annual PSA adjustment are limited to a cumulative plus or minus $0.004 per kWh over the life of the PSA;

• in addition, the ACC order provides for a PSA surcharge mechanism as follows:

• each time the accumulated pretax net deferrals reach $50 million, APS must notify the ACC, but prior to the deferral balance exceeding $100 million, APS must file with the ACC to recover or refund such deferral balance through a surcharge;

• amounts recovered or refunded through any surcharge are not included in the $0.004 per kWh PSA annual adjustment limit;

• the recoverable amount of Retail Fuel and Power Costs through current base rates and the PSA is capped at $776.2 million per year; and

• the PSA will remain in effect for a minimum five-year period, but the ACC may eliminate the PSA at any time, if appropriate, in the event APS files a rate case before the expiration of the five-year period or if APS does not comply with the terms of the PSA.

      The first regular annual adjustment to the PSA would be on April 1, 2006, and is expected to be for the full $0.004 per kWh permitted by the ACC’s order, which is in addition to the PSA surcharge requested on July 22, 2005 (see “Power Supply Adjustor” below).

• The 2004 Settlement Agreement included a prohibition against APS building generating plants to be in service prior to January 1, 2015. The ACC order modified that prohibition to include the acquisition of a generating unit, or an interest in a generating unit, from any utility or merchant generator without prior ACC approval.

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PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

• APS was authorized to acquire the PWEC Dedicated Assets from Pinnacle West Energy, with a net carrying value of approximately $850 million, and to rate base the PWEC Dedicated Assets at a rate base value of $700 million, which resulted in a mandatory rate base disallowance of approximately $150 million. This transfer was approved by the FERC on June 15, 2005 and completed on July 29, 2005. As a result, for financial reporting purposes, APS recognized a one-time, after-tax net plant regulatory disallowance of approximately $87 million during the third quarter of 2005.

• To bridge the time between the effective date of the rate increase and the actual date of the PWEC Dedicated Assets transfer, effective April 1, 2005, APS and Pinnacle West Energy entered into a cost-based purchase power agreement (the “Bridge PPA”), which was based on the value of the PWEC Dedicated Assets. When the Bridge PPA became effective, prior power purchase agreements entered into between APS and Pinnacle West Energy were terminated. The Bridge PPA was terminated on July 29, 2005, upon Pinnacle West Energy’s transfer of the PWEC Dedicated Assets to APS.

• Effective April 1, 2005, APS adopted longer service lives in accordance with the 2004 Settlement Agreement for certain depreciable assets. This change is expected to have the effect of reducing annual depreciation expense for financial reporting purposes by approximately $30 million. Also in accordance with the 2004 Settlement Agreement, APS adopted longer service lives for the PWEC Dedicated Assets, which is expected to have the effect of reducing annual depreciation expense for financial reporting purposes by approximately $10 million.

     Power Supply Adjustor

     On July 22, 2005, APS filed a surcharge application with the ACC requesting recovery of $100 million in deferred Retail Fuel and Power Costs under the PSA. APS later withdrew $20 million from its surcharge application, without prejudice, to limit issues and permit the timely implementation of the surcharge consistent with an adjustment mechanism. The withdrawn amount represents an estimate of replacement power costs associated with unplanned outages at Palo Verde between April 1, 2005 and July 31, 2005. Between April 1, 2005 and October 31, 2005, APS estimates that replacement power costs associated with unplanned outages at Palo Verde were approximately $40 million, including the $20 million of replacement power costs APS withdrew from its surcharge application. APS will seek full recovery of these expenses in a later proceeding in which the prudence of the expenses will be reviewed. Under ACC regulations, expenses are presumed to have been prudently incurred and this presumption may be set aside only by clear and convincing evidence that the expenses were unreasonable, dishonest, or obviously wasteful. APS believes these expenses were prudently incurred and are therefore recoverable.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     In the pending surcharge application, APS has requested recovery of $80 million of deferred Retail Fuel and Power Costs over a 24-month period beginning at year end, a rate increase of approximately 1.7% over that period. On October 17, 2005, the ACC staff filed testimony in support of APS’ request. An ACC hearing on this matter was held in late October, and a decision is expected by the end of the year.

     At September 30, 2005, APS’ pretax PSA deferrals were approximately $143 million, including the $80 million of deferred costs that are subject to the pending surcharge application. As noted under “APS 2003 Rate Case” above, the PSA includes a $776.2 million annual limit on the Retail Fuel and Power Costs that APS can recover through its current base rates and the PSA. Based on APS’ 2006 hedge position and forward market prices for natural gas as of October 31, 2005, APS estimates that its Retail Fuel and Power Costs in 2006 will be approximately $834 million before income taxes. APS further estimates that its Retail Fuel and Power Costs in 2006 will exceed the $776.2 million limit in the fourth quarter of 2006. In its recent rate case filing, APS requested that this limit be removed or increased (see “2005 General Rate Case” above).

     Equity Infusion Notice

     On July 20, 2005, Pinnacle West filed a Notice with the ACC indicating its intent to infuse more than $100 million of equity into APS during each of 2005, 2006, and subsequent years. Under Arizona law and decisions, Pinnacle West is required to give such notice at least 120 days prior to such an equity infusion into APS. The ACC may, but need not, take action on this Notice. If the ACC takes no action within the 120 day notice period, Pinnacle West may thereafter make the proposed equity infusions, at management’s discretion. On September 30, 2005, the ACC staff recommended approval of Pinnacle West infusing at least $450 million of equity into APS, including $100 million that Pinnacle West has already infused into APS during 2005 under a prior ACC decision. The $450 million consists of about $250 million related to Pinnacle West’s common equity issuance on May 2, 2005 (see Note 4) and about $200 million of proceeds from the pending Silverhawk sale (see Note 17). At the ACC Open Meeting on November 8, 2005, the ACC approved the equity infusion, including clarifying that Pinnacle West may make these equity infusions during 2005 or 2006.

     ACC Financing Order

     On May 12, 2003, APS issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund the repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. On April 11, 2005, this loan was repaid with the proceeds of a new debt issuance by Pinnacle West Energy. See “Capital Needs and Resources — By Company — Pinnacle West Energy” in Part I, Item 2 below.

     The ACC granted the Financing Order subject to various conditions. One of these conditions is that APS must maintain a common equity ratio of at least 40% and may not pay common dividends if such payment would reduce its common equity ratio below that threshold, unless otherwise waived by the ACC. This condition is an ongoing requirement and was not affected by Pinnacle West Energy’s repayment of APS’ $500 million loan.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     Retail Electric Competition Rules

     In 1999, the ACC approved rules for the introduction of retail electric competition in Arizona. The rules include the following major provisions:

• They apply to virtually all Arizona electric utilities regulated by the ACC, including APS.

• Effective January 1, 2001, retail access became available to all APS retail electricity customers.

• Electric service providers that get CC&N’s from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution.

• Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services.

• The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs.

     On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. The ACC and other parties aligned with the ACC appealed the ruling to the Arizona Court of Appeals, and in January 2004, the Court invalidated some, but not all, of the rules as either violative of Arizona’s constitutional requirement that the ACC consider the “fair value” of a utility’s property in setting rates or as being beyond the ACC’s constitutional and statutory powers. Other rules were set aside for failure to submit such regulations to the Arizona Attorney General for certification as required by statute. A request for the Arizona Supreme Court to review the Court of Appeals decision was denied on January 4, 2005. To date, the ACC has taken no action on either the rules or the orders authorizing competitive electric service providers in response to the now final Court of Appeals decision. As a result, at present only limited electric retail competition exists in Arizona and only with certain entities not regulated by the ACC.

     Track B Order

     On March 14, 2003, the ACC issued the Track B Order, which required APS to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. By May 6, 2003, APS entered into contracts to meet all or a portion of its requirements for the years 2003 through 2006 as follows:

(1) Pinnacle West Energy agreed to provide 1,700 MW in July through September of 2003 and in June through September of 2004, 2005, and 2006, by means of a unit contingent contract.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(2)	PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.
(3)	Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.

     With final ACC approval of the 2004 Settlement Agreement, the Track B contract with Pinnacle West Energy was cancelled, effective April 1, 2005 and replaced by the Bridge PPA. The Bridge PPA was terminated on July 29, 2005, upon Pinnacle West Energy’s transfer of the PWEC Dedicated Assets to APS. The Track B contract with PPL EnergyPlus, LLC was cancelled upon closing of the purchase of the Sundance Plant. On May 13, 2005, APS acquired the Sundance Plant from PPL Sundance for a purchase price of approximately $190 million.

     General

     Although some very limited retail competition existed in APS’ service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory.

Federal

     In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. Sales at prices above the cap must be justified and are subject to potential refund.

     On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to its 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 market-based rates for control areas other than those of APS, Public Service Company of New Mexico and Tucson Electric Power Company. The FERC staff has required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies have submitted such data. We cannot currently predict the outcome of this proceeding, but we do not believe that the outcome will have a material adverse effect on our financial position, results of operations or cash flows.

6. Retirement Plans and Other Benefits

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

     The following table provides details of the plans’ benefit costs for the three and nine months ended September 30, 2005 and 2004. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or amounts capitalized as overhead construction (dollars in millions):

	Pension Benefits												Other Benefits
	Three Months						Nine Months						Three Months						Nine Months
	Ended						Ended						Ended						Ended
	September 30,						September 30,						September 30,						September 30,
	2005			2004			2005			2004			2005			2004			2005			2004
Service cost-benefits earned during the period	$	11		$	10		$	34		$	31		$	5		$	4		$	16		$	13
Interest cost on benefit obligation		22			21			66			62			9			7			26			22
Expected return on plan assets		(22	)		(20	)		(67	)		(60	)		(8	)		(6	)		(23	)		(18	)
Amortization of:
Transition (asset) obligation		(1	)		(1	)		(3	)		(2	)		1			1			2			2
Prior service cost		1			1			2			2			—			—			—			—
Net actuarial loss		5			4			15			13			2			2			7			5
Net periodic benefit cost	$	16		$	15		$	47		$	46		$	9		$	8		$	28		$	24
Portion of cost charged to expense	$	7		$	7		$	20		$	21		$	4		$	4		$	12		$	11
APS’ share of costs charged to expense	$	6		$	6		$	18		$	18		$	4		$	3		$	11		$	9

Contributions

     Our minimum required 2005 pension contribution of approximately $53 million has been made for the year. We expect to contribute approximately $37 million to other postretirement benefit plans in 2005 and have contributed approximately $28 million of that amount through October 2005. APS’ share is approximately 96% of both plans.

7. Business Segments

     We have three principal business segments (determined by products, services and the regulatory environment):

• our regulated electricity segment, which consists of traditional regulated retail and wholesale electricity businesses (primarily electricity service to Native Load customers) and related activities and includes electricity generation, transmission and distribution;

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services; and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

• our real estate segment, which consists of SunCor’s real estate development and investment activities.

     Financial data for the three and nine months ended September 30, 2005 and 2004 and at September 30, 2005 and December 31, 2004 by business segment is provided as follows (dollars in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005			2004
Operating Revenues:
Regulated electricity (a)	$	754	$	671	$	1,749		$	1,606
Marketing and trading (a)		107		91		267			290
Real estate		79		73		233			187
Other		16		12		47			33
Total	$	956	$	847	$	2,296		$	2,116
Net Income (Loss):
Regulated electricity (b)	$	70	$	94	$	152		$	152
Marketing and trading (c)		8		4		(46	)		19
Real estate		21		5		42			12
Other (d)		5		2		7			26
Total	$	104	$	105	$	155		$	209

(a)	Effective April 1, 2005, revenues of approximately $20 million from Off-System Sales, which would have previously been reported in the marketing and trading segment, are now included in the regulated electricity segment in accordance with the retail rate settlement.
(b)	The 2005 periods include an $87 million (after-tax) regulatory disallowance in accordance with the 2004 Settlement Agreement. See Note 5.
(c)	The nine months ended September 30, 2005 includes a $64 million (after-tax) loss in discontinued operations related to the pending sale of Silverhawk.
(d)	The nine months ended September 30, 2004 includes a $21 million (after-tax) gain related to the sale of a limited partnership interest in the Phoenix Suns. The three and nine months ended September 30, 2005 include recognition of a previously contingent $4 million (after-tax) gain in connection with the 2004 sale of NAC.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	As of		As of
	September 30, 2005		December 31, 2004
Assets:
Regulated electricity	$	10,608	$	8,674
Marketing and trading		980		746
Real estate		447		454
Other		33		23
Total	$	12,068	$	9,897

8. New Accounting Standards

     In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment.” The standard establishes accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123(R) is effective for us as of January 1, 2006. We have evaluated the impacts of this new guidance and do not believe it will have a material impact on our financial statements.

     In March 2005, the FASB issued FIN No. 47, “Accounting for Conditional Asset Retirement Obligations.” FIN No. 47 clarifies that an entity must record a liability for the fair value of an asset retirement obligation for which the timing and/or method of settlement are conditional on a future event if the liability’s fair value can be reasonably estimated. FIN No. 47 is effective no later than the end of fiscal years ending after December 15, 2005. We have evaluated the impact of this new guidance and do not believe it will have a material impact on our financial statements.

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 September 30, 2005, APS would have been required to assume approximately $245 million of debt and pay the equity participants approximately $191 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 well as interest rate risk associated with

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

long-term debt. As of September 30, 2005, we hedged exposures to the price variability of the power and gas commodities for a maximum of three years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Cash Flow Hedges

     The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three and nine months ended September 30, 2005 and 2004 were comprised of the following (dollars in thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005		2004
Gains on the ineffective portion of derivatives qualifying for hedge accounting	$	4,667	$	138	$	12,444	$	1,610
Gains from the change in options’ time value excluded from measurement of effectiveness		17		—		756		63
Gains from the discontinuance of cash flow hedges		—		—		385		1,137

     During the twelve months ending September 30, 2006, we estimate that a net gain of $319 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for recovery through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

     Our assets and liabilities from risk management and trading activities are presented in two categories, consistent with our business segments:

• Regulated Electricity — non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and

• Marketing and Trading — both non-trading and trading derivative instruments of our competitive business segment.

     The following table summarizes our assets and liabilities from risk management and trading activities at September 30, 2005 and December 31, 2004 (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	649,317	$	242,196	$	(384,657	)	$	(73,597	)	$	433,259
Futures and options margin account		245		—		(185,213	)		—			(184,968	)
Marketing and trading:
Mark-to-market		304,289		301,509		(207,314	)		(164,705	)		233,779
Options and futures and emission allowances — at cost		1,903		993		(24,413	)		—			(21,517	)
Total	$	955,754	$	544,698	$	(801,597	)	$	(238,302	)	$	460,553

December 31, 2004

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	45,220	$	19,417	$	(19,191	)	$	(12,000	)	$	33,446
Futures and options margin account		18,821		118		(8,879	)		—			10,060
Marketing and trading:
Mark-to-market		102,855		204,512		(68,008	)		(132,683	)		106,676
Options and futures and emission allowances — at cost		—		294		(17,328	)		(11,579	)		(28,613	)
Total	$	166,896	$	224,341	$	(113,406	)	$	(156,262	)	$	121,569

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $185 million at September 30, 2005 and $9 million at December 31, 2004 and is included in the futures and options margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

     Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $7 million at September 30, 2005 and $1 million at December 31, 2004, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $254 million at September 30, 2005 and $24 million at December 31, 2004, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Fair Value Hedges

     On January 29, 2004, we entered into two fixed-for-floating interest rate swap transactions on our $300 million 6.4% Senior Notes. The purpose of these hedges is to protect against significant fluctuations in the fair value of our debt. Our interest rate swaps are considered to be fully effective with any resulting gains or losses on the derivative offset by a similar loss or gain amount on the underlying fair value of our debt. The fair value of the interest rate swaps was a loss of approximately $3.1 million at September 30, 2005 and is included in other current liabilities with the corresponding offset in current maturities of long-term debt on the Condensed Consolidated Balance Sheets.

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 $1.5 billion of risk management and trading assets as of September 30, 2005. Our risk management process assesses and monitors the financial exposure of these and all other counterparties. Despite the fact that the great majority of trading counterparties 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 major energy companies, municipalities, local distribution companies and financial institutions. 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. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. 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 nine months ended September 30, 2005 and 2004, are as follows (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income	$	103,737		$	105,400		$	154,920		$	209,466
Other comprehensive income:
Net unrealized gains on derivative instruments (a)		389,474			27,645			524,898			100,933
Net reclassification of realized gains to income (b)		(41,455	)		(14,525	)		(57,143	)		(21,005	)
Net income tax expense related to items of other comprehensive income		(136,528	)		(5,153	)		(183,500	)		(31,389	)
Total other comprehensive income		211,491			7,967			284,255			48,539
Comprehensive income	$	315,228		$	113,367		$	439,175		$	258,005

(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. This increase is primarily due to increases 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.

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 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 2010 and it does not intend to begin accepting spent nuclear fuel prior to that date. 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. Arizona Public Service Company v. United States of America, United States Court of Federal Claims, 03-2832C.

     APS currently estimates it will incur $147 million (in 2004 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 September 30, 2005, APS had a regulatory asset of $8 million that represents amounts spent for

24

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

on-site interim spent fuel storage net of amounts recovered in rates per the ACC rate order that was effective April 1, 2005.

California Energy Market Issues and Refunds in the Pacific Northwest

     FERC

     In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision in Bonneville Power Administration v. FERC, No. 70262, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. San Diego Gas & Electric Co. v. Sellers of Energy and Ancillary Services Into Markets Operated by the California Independent System Operator and the California Power Exchange Corp., 112 FERC ¶ 61,176 (2005). More than twenty sellers made such cost recovery filings on September 14, 2005. If the FERC accepts these filings, the refund liability for these sellers will be reduced, thereby reducing the recovery of total refunds in the California markets. Although APS anticipates that it will be entitled to a net refund once the final calculations are complete, the actual recovery of the full amount of such refunds is uncertain at this time.

     On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. State of California v. British Columbia Power Exchange et al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. State of California ex rel. Bill Lockyer, Attorney General v. FERC, No. 02-73093. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing has not been acted upon, and the outcome of the further proceedings cannot be predicted at this time.

     The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals. Although the FERC

25

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

ruling in the Pacific Northwest matter is being appealed and the FERC has not yet calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or cash flows.

     On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000-2001 time period, including APS, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the Independent System Operator tariff. After reviewing the matter, along with the data supplied by APS, the FERC staff moved to dismiss the claims against APS and to dismiss the proceeding. The motion to dismiss was granted by the FERC on January 22, 2004. Certain parties have sought rehearing of this order, and that request is pending.

     California Civil Energy Market Litigation

     The State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and California independent system operator markets, including APS, attempting to expand those matters to such other participants. On October 3, 2005, the San Diego Superior Court granted a motion to dismiss the complaint brought by certain defendants. Duke and Reliant were not part of that group of defendants because they had reached a tentative settlement with the plaintiffs. The settlements must now be approved by the court and the class members before becoming final. If approved, the cross-complaint against APS by Duke and Reliant would remain pending, although APS and the other cross-defendants have entered into negotiations with Duke and Reliant that may result in the conditional dismissal of the cross-complaints.

     APS was also named as a defendant in James Millar, et al. v. Allegheny Energy Supply, et al., Case No. CGC02-0407867, San Francisco Superior Court, a lawsuit regarding wholesale contracts in California. The case was removed to the federal court (Northern District of California Case No. C-04-0519 SBA) and then sent back to state court. The First Amended Complaint alleged basically that the contracts entered into were the result of an unfair and unreasonable market, in violation of California unfair competition laws. This case was dismissed on September 7, 2005 when the court granted defendants’ motion to dismiss without leave to amend.

Natural Gas Supply

     Pursuant to the terms of a comprehensive settlement entered into in 1996 with El Paso Natural Gas Company, the rates charged for natural gas transportation are subject to a rate moratorium through December 31, 2005.

     On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter

26

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the costs responsibility associated with the changed contractual obligations in a way that would be less favorable to APS and Pinnacle West Energy than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS and Pinnacle West Energy’s annual capacity cost could be increased by approximately $3 million per year, for the period September 2003 through December 2005. This appeal has been stayed pending further consideration by the FERC.

     Consistent with its obligations under the 1996 settlement, El Paso filed a new rate case on June 30, 2005, which proposes new rates and new services to become effective on January 1, 2006. The FERC suspended the effectiveness of these new rates and services until January 1, 2006 and made the rates subject to refund pending the outcome of a hearing. As part of an ongoing technical conference and settlement discussions, El Paso has agreed to postpone the implementation and the associated cost impact of the new services until April 1, 2006. APS is currently evaluating the cost impact of these new services.

Navajo Nation Litigation

     In June 1999, the Navajo Nation served Salt River Project with a 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. The Navajo Nation v. Peabody Holding Company, Inc., et al., United States District Court for the District of Columbia, CA-99-0469-EGS (the “D.C. Lawsuit”). 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 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”. Peabody Western Coal Company v. Salt River Project Agricultural Improvement and Power District, et al., Circuit Court for the City of St. Louis, Division No. 1, Cause No. 042-08561. Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.

Environmental Matters

     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

27

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.

Litigation

     We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our 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 programs 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 $17.8 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

14. Other Income and Other Expense

     The following table provides detail of other income and other expense for the three and nine months ended September 30, 2005 and 2004 (dollars in thousands):

28

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Other income:
Investment gains — net (a)	$	162		$	—		$	—		$	36,945
Interest income		6,815			1,319			12,006			4,648
SunCor (b)		312			838			2,654			4,029
Asset sales		1,299			33			1,683			2,495
Miscellaneous		106			596			1,676			1,863
Total other income	$	8,694		$	2,786		$	18,019		$	49,980
Other expense:
Non-operating costs (c)	$	(4,084	)	$	(3,642	)	$	(10,240	)	$	(10,302	)
Asset sales		(71	)		(649	)		(384	)		(221	)
Investment losses — net		—			(136	)		(164	)		—
Miscellaneous		(760	)		(667	)		(2,197	)		(3,751	)
Total other expense	$	(4,915	)	$	(5,094	)	$	(12,985	)	$	(14,274	)

(a)	The nine months ended September 30, 2004 includes a $35 million gain ($21 million after-tax) related to the sale of a limited partnership interest in the Phoenix Suns.
(b)	Includes joint venture and other non-operating income.
(c)	As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).

15. Guarantees

     We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our unregulated subsidiaries. Our parental guarantees for Pinnacle West Energy primarily relate to environmental permits and a purchased power agreement. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our unregulated subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle West’s guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantee. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at September 30, 2005 are as follows (dollars in millions):

29

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Energy	$	12		1	$	—		—
APS Energy Services		26		1		68		1
Total	$	38			$	68

     At September 30, 2005, we had entered into approximately $37 million of letters of credit which support transmission agreements related to Silverhawk. These letters of credit expire in 2006. See Note 17 for discussion of pending sale of Silverhawk. 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. At September 30, 2005, Pinnacle West had approximately $4 million of letters of credit related to workers’ compensation expiring in 2006.

     APS has entered into various agreements that require letters of credit for financial assurance purposes. At September 30, 2005, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations. In October 2005, $150 million of these letters of credit were renewed for a five-year term and expire in 2010. The remainder also expire in 2010. APS has also entered into approximately $98 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, APS has approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2006. 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. 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.

     See Note 4 for information regarding Pinnacle West’s guarantee of $500 million of Pinnacle West Energy’s debt obligations and Pinnacle West Energy’s subsequent repayment of the debt obligations on October 3, 2005.

16. Earnings Per Share

     The following table presents earnings per weighted average common share outstanding for the three and nine months ended September 30, 2005 and 2004:

30

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005			2004
Basic earnings per share:
Income from continuing operations	$	0.86	$	1.14	$	2.08		$	2.29
Income (loss) from discontinued operations		0.19		0.01		(0.46	)		—
Earnings per share — basic	$	1.05	$	1.15	$	1.62		$	2.29
Diluted earnings per share:
Income from continuing operations	$	0.86	$	1.14	$	2.08		$	2.28
Income (loss) from discontinued operations		0.19		0.01		(0.46	)		0.01
Earnings per share — diluted	$	1.05	$	1.15	$	1.62		$	2.29

     Dilutive stock options increased average common shares outstanding by approximately 119,000 shares and 134,000 shares for the three months ended September 30, 2005 and September 30, 2004, respectively, and by approximately 113,000 shares and 108,000 shares for the nine months ended September 30, 2005 and September 30, 2004, respectively.

     Options to purchase 167,604 shares for the three-month period ended September 30, 2005 and 503,304 shares of common stock for the nine-month period ended September 30, 2005 were outstanding but were not included in the computation of 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 not included in the computation of diluted earnings per share for that same reason were 985,469 shares for the three-month period ended September 30, 2004 and 1,088,378 shares for the nine-month period ended September 30, 2004.

17. Discontinued Operations

     Silverhawk (marketing and trading segment) — In June 2005, we entered into an agreement to sell our 75% interest in Silverhawk to NPC. The Nevada Public Utilities Commission approved the sale in September 2005. Closing of the sale is subject to additional regulatory approvals, including approval by the FERC and clearance by the Federal Trade Commission, which are expected to be received in the fourth quarter of 2005. As a result of this pending sale, we recorded an after-tax loss from discontinued operations of approximately $55 million ($91 million pre-tax) in the second quarter of 2005. The marketing and trading segment discontinued operations amounts in the chart below also include the revenues and expenses related to the operations of Silverhawk. The assets held for sale at September 30, 2005 were $204 million, of which property, plant and equipment accounted for approximately $198 million.

     Concurrent with the execution of the agreement to sell our interest in Silverhawk, GenWest and NPC also entered into a Purchase Power Agreement (the “PPA”) providing for the sale of GenWest’s share of the capacity and output of Silverhawk to NPC commencing on the later of October 1, 2005 or the first business day of the month following NPUC approval of the PPA. The PPA commenced on October 1, 2005 following the NPUC approval described in the preceding

31

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

paragraph. The PPA will terminate upon the earlier of the closing of the sale under the Purchase Agreement or September 30, 2006.

     SunCor (real estate segment) — In 2005, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. As a result of the sales, we recorded an after-tax gain from discontinued operations of approximately $15 million ($25 million pre-tax) in July 2005.

     NAC (other segment) — In 2004, we sold our investment in NAC, and the third quarter of 2005 includes recognition of a previously contingent $4 million (after-tax) gain in connection with the sale.

     The following table provides revenue and income (loss) before income taxes and after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2005 and 2004 (dollars in millions):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005			2004
Revenue:
Silverhawk	$	45	$	37		$	88		$	42
SunCor — commercial operations		2		10			9			16
NAC		—		8			—			27
Total revenue	$	47	$	55		$	97		$	85
Income (loss) before taxes:
Silverhawk	$	1	$	(1	)	$	(106	)	$	(5	)
SunCor — commercial operations		24		2			27			4
NAC		6		—			6			2
Total income (loss) before taxes	$	31	$	1		$	(73	)	$	1
Income (loss) after taxes:
Silverhawk	$	1	$	—		$	(64	)	$	(3	)
SunCor — commercial operations		14		1			16			2
NAC		4		—			4			1
Total income (loss) after taxes	$	19	$	1		$	(44	)	$	—

32

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(unaudited)

(dollars in thousands)

	Three Months Ended
	September 30,
	2005			2004
ELECTRIC OPERATING REVENUES (LOSSES)
Regulated electricity	$	755,778		$	675,089
Marketing and trading		(7,430	)		25,423
Total		748,348			700,512
OPERATING EXPENSES
Regulated electricity fuel and purchased power		219,420			237,035
Marketing and trading fuel and purchased power		223			23,130
Operations and maintenance		149,198			143,338
Depreciation and amortization		81,701			81,177
Income taxes		88,984			57,137
Other taxes		34,407			29,013
Total		573,933			570,830
OPERATING INCOME		174,415			129,682
OTHER INCOME (DEDUCTIONS)
Regulatory disallowance (Note 5)		(143,217	)		—
Income taxes		60,265			(1,383	)
Allowance for equity funds used during construction		2,852			(1,327	)
Other income (Note S-4)		4,954			6,374
Other expense (Note S-4)		(3,835	)		(2,670	)
Total		(78,981	)		994
INTEREST DEDUCTIONS
Interest on long-term debt		33,583			36,324
Interest on short-term borrowings		1,753			1,425
Debt discount, premium and expense		914			1,233
Capitalized interest		(1,909	)		(3,498	)
Total		34,341			35,484
NET INCOME	$	61,093		$	95,192

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)

	Nine Months Ended
	September 30,
	2005			2004
ELECTRIC OPERATING REVENUES
Regulated electricity	$	1,755,969		$	1,619,361
Marketing and trading		22,428			91,911
Total		1,778,397			1,711,272
OPERATING EXPENSES
Regulated electricity fuel and purchased power		503,205			488,294
Marketing and trading fuel and purchased power		31,874			94,774
Operations and maintenance		429,806			396,121
Depreciation and amortization		240,723			258,410
Income taxes		147,136			106,870
Other taxes		97,174			86,467
Total		1,449,918			1,430,936
OPERATING INCOME		328,479			280,336
OTHER INCOME (DEDUCTIONS)
Regulatory disallowance (Note 5)		(143,217	)		—
Income taxes		57,879			(5,153	)
Allowance for equity funds used during construction		8,407			2,859
Other income (Note S-4)		17,618			22,192
Other expense (Note S-4)		(10,069	)		(8,709	)
Total		(69,382	)		11,189
INTEREST DEDUCTIONS
Interest on long-term debt		104,712			103,967
Interest on short-term borrowings		4,999			5,141
Debt discount, premium and expense		3,106			3,616
Capitalized interest		(5,856	)		(5,754	)
Total		106,961			106,970
NET INCOME	$	152,136		$	184,555

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)

	September 30,			December 31,
	2005			2004
ASSETS
UTILITY PLANT
Electric plant in service and held for future use	$	10,546,772		$	9,120,407
Less accumulated depreciation and amortization		3,610,320			3,266,181
Total		6,936,452			5,854,226
Construction work in progress		332,623			249,243
Intangible assets, net of accumulated amortization		108,270			103,701
Nuclear fuel, net of accumulated amortization		59,889			51,188
Utility plant — net		7,437,234			6,258,358
INVESTMENTS AND OTHER ASSETS
Note receivable from Pinnacle West Energy (Note S-5)		—			498,489
Decommissioning trust accounts		290,537			267,700
Assets from long-term risk management and trading activities (Note S-2)		250,607			20,123
Other assets		60,339			61,364
Total investments and other assets		601,483			847,676
CURRENT ASSETS
Cash and cash equivalents		721,835			49,575
Investments in debt securities		18,600			181,175
Customer and other receivables		449,290			353,772
Allowance for doubtful accounts		(3,763	)		(3,444	)
Materials and supplies (at average cost)		106,427			83,893
Fossil fuel (at average cost)		25,458			20,506
Assets from risk management and trading activities (Note S-2)		668,382			70,430
Other current assets		7,177			10,187
Total current assets		1,993,406			766,094
DEFERRED DEBITS
Deferred fuel and purchased power regulatory asset (Note 5)		142,806			—
Other regulatory assets		145,592			135,051
Unamortized debt issue costs		25,488			21,832
Other deferred debits		66,643			69,541
Total deferred debits		380,529			226,424
TOTAL ASSETS	$	10,412,652		$	8,098,552

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)

	September 30,			December 31,
	2005			2004
CAPITALIZATION AND LIABILITIES
CAPITALIZATION
Common stock	$	178,162		$	178,162
Additional paid-in capital		1,703,098			1,246,804
Retained earnings		969,831			860,196
Accumulated other comprehensive income (loss):
Minimum pension liability adjustment		(71,087	)		(71,087	)
Derivative instruments		237,150			18,327
Common stock equity		3,017,154			2,232,402
Long-term debt less current maturities		2,563,591			2,267,094
Total capitalization		5,580,745			4,499,496
CURRENT LIABILITIES
Current maturities of long-term debt		1,877			451,247
Accounts payable		233,687			215,076
Accrued taxes		395,102			292,521
Accrued interest		35,766			33,332
Customer deposits		54,860			51,804
Deferred income taxes		9,057			9,057
Liabilities from risk management and trading activities (Note S-2)		596,920			34,292
Account payable to Pinnacle West Energy (Note S-5)		500,000			—
Other current liabilities		221,852			91,441
Total current liabilities		2,049,121			1,178,770
DEFERRED CREDITS AND OTHER
Deferred income taxes		1,330,510			1,108,571
Regulatory liabilities		569,863			506,646
Liability for asset retirements		263,457			251,612
Pension liability		197,501			203,668
Customer advances for construction		59,807			59,185
Unamortized gain — sale of utility plant		46,901			50,333
Liabilities from long term risk management and trading activities (Note S-2)		86,500			13,124
Other		228,247			227,147
Total deferred credits and other		2,782,786			2,420,286
COMMITMENTS AND CONTINGENCIES (Notes 5, 12, 13, 15 and S-5)
TOTAL CAPITALIZATION AND LIABILITIES	$	10,412,652		$	8,098,552

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)

	Nine Months Ended
	September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	152,136		$	184,555
Adjustments to reconcile net income to net cash provided by operating activities:
Regulatory disallowance		143,217			—
Depreciation and amortization including nuclear fuel		262,647			281,803
Deferred fuel and purchased power		(142,806	)		—
Allowance for equity funds used during construction		(8,407	)		(2,859	)
Deferred income taxes		9,959			5,259
Change in mark-to-market valuations		4,300			(20,666	)
Changes in current assets and liabilities:
Customer and other receivables		(97,604	)		(125,130	)
Materials, supplies and fossil fuel		(10,759	)		4,397
Other current assets		3,299			(189	)
Accounts payable		10,697			69,585
Other current liabilities		237,720			166,271
Increase in regulatory assets		(10,541	)		(4,838	)
Increase in regulatory liabilities		—			16,764
Change in customer advances		622			8,938
Change in other long-term assets		12,050			1,951
Change in other long-term liabilities		205,861			41,383
Net cash flow provided by operating activities		772,391			627,224
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(459,737	)		(329,759	)
Purchase of Sundance Plant		(185,046	)		—
Capitalized interest		(5,856	)		(5,754	)
Repayment of loan by Pinnacle West Energy		500,000			—
Purchases of investment securities		(1,338,624	)		(517,050	)
Proceeds from sale of investment securities		1,501,199			340,745
Other		(13,118	)		(10,914	)
Net cash flow used for investing activities		(1,182	)		(522,732	)
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of long-term debt		411,787			476,240
Equity infusion		100,000			—
Dividends paid on common stock		(42,500	)		(127,500	)
Repayment and reacquisition of long-term debt		(568,236	)		(385,424	)
Net cash flow used for financing activities		(98,949	)		(36,684	)
NET INCREASE IN CASH AND CASH EQUIVALENTS		672,260			67,808
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		49,575			288,307
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	721,835		$	356,115
Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes paid, net of refunds	$	29,058		$	8,152
Interest, net of amounts capitalized	$	101,422		$	106,557

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

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     Certain notes to APS’ Condensed Financial Statements are combined with the Notes to Pinnacle West’s Condensed Consolidated Financial Statements. Listed below are the Condensed Consolidated Notes to Pinnacle West’s Condensed Consolidated Financial Statements, the majority of which also relate to APS’ Condensed Financial Statements. In addition, listed below are the Supplemental Notes which are required disclosures for APS and should be read in conjunction with Pinnacle West’s Condensed Consolidated Notes.

	Condensed		APS’
	Consolidated		Supplemental
	Footnote		Footnote
	Reference		Reference
Consolidation and Nature of Operations	Note 1			—
Condensed Consolidated Financial Statements	Note 2			—
Quarterly Fluctuations	Note 3			—
Changes in Liquidity	Note 4		Note S-1
Regulatory Matters	Note 5			—
Retirement Plans and Other Benefits	Note 6			—
Business Segments	Note 7			—
New Accounting Standards	Note 8			—
Variable Interest Entities	Note 9			—
Derivative and Energy Trading Accounting	Note 10		Note S-2
Comprehensive Income	Note 11		Note S-3
Commitments and Contingencies	Note 12			—
Nuclear Insurance	Note 13			—
Other Income and Other Expense	Note 14		Note S-4
Guarantees	Note 15			—
Earnings Per Share	Note 16			—
Discontinued Operations	Note 17			—
Related Party Transactions		—	Note S-5

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-1. Changes in Liquidity

     The following is a list of principal payments due on APS’ total long-term debt and capitalized lease requirements:

• $1 million in 2005;

• $86 million in 2006;

• $28 million in 2007;

• $1 million in 2008;

• $1 million in 2009; and

• $2.458 billion, thereafter.

S-2. Derivative and Energy Trading Accounting

     APS is exposed to the impact of market fluctuations in the commodity price of electricity, natural gas and coal. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity and fuels. As of September 30, 2005, APS hedged exposures to these risks for a maximum of three years.

Cash Flow Hedges

     The changes in the fair value of APS’ hedged positions included in the APS Condensed Statements of Income, after consideration of amounts deferred under the PSA, for the three and nine months ended September 30, 2005 and 2004 were comprised of the following (dollars in thousands):

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2005		2004			2005		2004
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	4,722	$	(59	)	$	12,590	$	1,477
Gains from the change in options’ time value excluded from measurement of effectiveness		17		—			756		63
Gains from the discontinuance of cash flow hedges		—		—			302		575

     During the twelve months ending September 30, 2006, we estimate that a net gain of $244 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible to be recovered through the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

     APS’ assets and liabilities from risk management and trading activities are presented in two categories, consistent with Pinnacle West’s business segments:

39

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

• Regulated Electricity — non-trading derivative instruments that hedge APS’ purchases and sales of electricity and fuel for its Native Load requirements; and

• Marketing and Trading — both non-trading and trading derivative instruments.

     The following table summarizes APS’ assets and liabilities from risk management and trading activities at September 30, 2005 and December 31, 2004 (dollars in thousands):

September 30, 2005

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	649,317	$	242,196	$	(384,657	)	$	(73,597	)	$	433,259
Futures and options margin account		245		—		(185,213	)		—			(184,968	)
Marketing and Trading:
Mark-to-market		16,917		8,160		(26,371	)		(12,903	)		(14,197	)
Options at cost		1,903		251		(679	)		—			1,475
Total	$	668,382	$	250,607	$	(596,920	)	$	(86,500	)	$	235,569

December 31, 2004

			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	45,220	$	19,417	$	(19,191	)	$	(12,000	)	$	33,446
Futures and options margin account		18,821		118		(8,879	)		—			10,060
Marketing and Trading:
Mark-to-market		6,389		581		(6,222	)		(1,124	)		(376	)
Options at cost		—		7		—			—			7
Total	$	70,430	$	20,123	$	(34,292	)	$	(13,124	)	$	43,137

     We maintain a margin account with a broker to support our risk management and trading activities. The margin account was a liability of $185 million at September 30, 2005 and $9 million at December 31, 2004 and is included in the futures and options margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

     Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. No collateral was provided to counterparties at September 30, 2005 or December 31, 2004. Collateral provided to us by counterparties was $159 million at September 30, 2005 and $6 million at December 31, 2004, and is included in other current liabilities on the Condensed Balance Sheets.

40

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-3. Comprehensive Income

     Components of APS’ comprehensive income for the three and nine months ended September 30, 2005 and 2004, are as follows (dollars in thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Net income	$	61,093		$	95,192		$	152,136		$	184,555
Other comprehensive income:
Net unrealized gains on derivative instruments (a)		315,532			20,030			399,602			68,109
Net reclassification of realized gains to income (b)		(32,868	)		(10,985	)		(38,687	)		(17,813	)
Net income tax expense related to items of other comprehensive income		(111,285	)		(3,568	)		(142,092	)		(19,837	)
Total other comprehensive income		171,379			5,477			218,823			30,459
Comprehensive income	$	232,472		$	100,669		$	370,959		$	215,014

(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. This increase is primarily due to increases in forward natural gas prices and wholesale electricity prices.
(b)	These amounts primarily include the reclassification of unrealized gains and losses to realized gains and losses for contracted commodities delivered during the period.

S-4. Other Income and Other Expense

     The following table provides detail of APS’ other income and other expense for the three and nine months ended September 30, 2005 and 2004 (dollars in thousands):

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ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004
Other income:
Interest income	$	3,408		$	5,857		$	13,008		$	15,908
Asset sales		1,299			33			1,683			2,495
Investment gains — net		34			—			513			2,312
Miscellaneous		213			484			2,414			1,477
Total other income	$	4,954		$	6,374		$	17,618		$	22,192
Other expense:
Non-operating costs (a)	$	(3,358	)	$	(1,793	)	$	(8,693	)	$	(6,336	)
Asset sales		(71	)		(123	)		(384	)		(391	)
Investment losses — net		—			(85	)		—			—
Miscellaneous		(406	)		(669	)		(992	)		(1,982	)
Total other expense	$	(3,835	)	$	(2,670	)	$	(10,069	)	$	(8,709	)

(a) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and other costs excluded from utility rate recovery).

S-5. Related Party Transactions

     From time to time, APS enters into transactions with Pinnacle West or Pinnacle West’s subsidiaries. The following table summarizes the amounts included in the APS Condensed Statements of Income and Condensed Balance Sheets related to transactions with affiliated companies (dollars in millions):

	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
	2005		2004		2005		2004
Electric operating revenues:
Pinnacle West — marketing and trading	$	2	$	4	$	5	$	12
Pinnacle West Energy		—		—		2		1
Total	$	2	$	4	$	7	$	13
Purchased power and fuel costs:
Pinnacle West Energy	$	14	$	34	$	61	$	63
Other:
Pinnacle West Energy interest income	$	—	$	5	$	5	$	14

42

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

	As of			As of
	September 30, 2005			December 31, 2004
Net intercompany receivables (payables):
Pinnacle West Energy	$	(500	)	$	467
Pinnacle West — marketing and trading		15			19
APS Energy Services		2			9
Pinnacle West		(3	)		(5	)
Total	$	(486	)	$	490

     Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. APS purchases electricity from and sells electricity to APS Energy Services; however, these transactions are settled net and reported net in accordance with EITF 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not ‘Held for Trading Purposes’ As Defined in EITF Issue No. 2-3.”

     Intercompany receivables primarily include amounts related to the intercompany sales of electricity. The December 31, 2004 intercompany receivable included a $500 million loan that APS made to Pinnacle West Energy. This loan was repaid in May 2005. See Note 4. Intercompany payables primarily include amounts related to the intercompany purchases of electricity. In connection with APS’ acquisition of the PWEC Dedicated Assets, APS recorded a $500 million intercompany payable to Pinnacle West Energy. On October 3, 2005, APS settled the intercompany payable. Intercompany receivables and payables are generally settled on a current basis in cash.

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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. Through its marketing and trading division, APS also generates, sells and delivers electricity to wholesale customers in the western United States. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.

     Pinnacle West Energy is our unregulated generation subsidiary. Pursuant to the ACC’s April 7, 2005 order in APS’ 2003 rate case, on July 29, 2005, Pinnacle West Energy transferred the PWEC Dedicated Assets to APS. See “APS 2003 Rate Case” in Note 5. As a result, Pinnacle West Energy’s remaining generating plant is a 75% interest in Silverhawk, a 570 MW combined cycle plant located north of Las Vegas, Nevada. See Note 17 of Notes to Condensed Consolidated Financial Statements for a discussion of the pending sale of our 75% interest in this plant, which is expected to close in the fourth quarter of 2005.

     The ACC regulates APS’ retail electric rates and its issuance of securities. The ACC must also approve any transfer of APS’ property used to provide retail electric service and approve or receive prior notification of certain transactions between Pinnacle West, APS, and their respective affiliates. APS’ financial condition and results of operations are dependent upon timely regulatory recovery through retail rates.

     As part of the ACC order in APS’ 2003 rate case, the ACC approved the PSA, which permits APS to defer for recovery or refund Retail Fuel and Power Costs, subject to specified parameters and procedures. APS has requested ACC approval of a PSA surcharge to recover $80 million in deferred Retail Fuel and Power Costs over a 24-month period beginning at year end. See “Power Supply Adjustor” in Note 5.

     Based on recent forward market prices for natural gas and purchased power (which are subject to change) and APS’ hedged positions at September 30, 2005, APS estimates that its pretax PSA deferrals will be approximately $160 million at December 31, 2005 and approximately $260 million by December 31, 2006. These estimates assume a PSA rate adjustment on April 1, 2006 pursuant to the PSA’s terms as well as the ACC’s approval of the requested $80 million PSA surcharge. If the ACC does not approve the requested PSA surcharge, APS estimates that its pretax PSA deferrals would be approximately $290 million by the end of 2006. APS estimates that its 2006 Retail Fuel and Power Costs will exceed the PSA’s $776.2 million annual limit. In its 2005 rate case filing, APS has requested that this limit be removed or increased. See “Power Supply Adjustor” in Note 5.

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     On November 4, 2005, APS filed a general rate case with the ACC seeking a $409.1 million, or 19.9%, increase in its annual retail electric revenues effective no later than December 31, 2006. In its filing, APS also seeks modifications to the existing PSA. See “APS 2005 General Rate Case” in Note 5.

     SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings and cash flow, particularly during the years 2003 through 2005 due to accelerated asset sales activity.

     Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures.

     We continue to focus on solid operational performance in our electricity generation and delivery activities. In the delivery area, we focus on superior reliability and customer satisfaction. We plan to expand long-term resources and our transmission and distribution systems to meet the electricity needs of our growing retail customers and sustain reliability.

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

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

     We have three principal business segments (determined by products, services and the regulatory environment):

• 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;

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading and APS Energy Services’ commodity-related energy services; and

• our real estate segment, which consists of SunCor’s real estate development and investment activities.

45

     The following table summarizes net income for the three-months and nine-months ended September 30, 2005 and 2004 (dollars in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2005		2004		2005			2004
Regulated electricity	$	70	$	94	$	152		$	152
Marketing and trading		7		4		18			22
Real estate		7		4		26			10
Other (a)		1		2		3			25
Income from continuing operations		85		104		199			209
Discontinued operations — net of tax:
Marketing and trading (b)		1		—		(64	)		(3	)
Real estate (c)		14		1		16			2
Other (d)		4		—		4			1
Net income	$	104	$	105	$	155		$	209

(a)	The nine months ended September 30, 2004 includes a $21 million (after-tax) gain related to the sale of a limited partnership interest in the Phoenix Suns.
(b)	See “Pending Sale of Silverhawk” below.
(c)	Primarily relates to the sale of commercial properties.
(d)	Primarily relates to additional gain from the sale of NAC.

General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.3 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business segments. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior-period amounts to conform to our current-period presentation.

Pending Sale of Silverhawk

     In June 2005, we entered into an agreement to sell our 75% interest in Silverhawk to Nevada Power Company. The Nevada Public Utilities Commission approved the sale in September 2005. Closing of the sale is subject to additional regulatory approvals, including approval by the FERC and clearance by the Federal Trade Commission, which are expected to be received in the fourth quarter of 2005. As a result of this pending sale, we recorded an after-tax loss from discontinued operations of approximately $55 million in the second quarter of 2005. The marketing and trading segment

46

discontinued operations amounts in the chart above also include the revenues and expenses related to the operations of Silverhawk.

Deferred Fuel and Purchased Power Costs

     APS’ retail rate settlement became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund Retail Fuel and Power Costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual Retail Fuel and Power Costs and the amount of such costs currently included in base rates. Actual Retail Fuel and Power Costs are higher than prior periods primarily due to higher fuel prices. The current base rate for Retail Fuel and Power Costs is based on 2003 price levels, and spot prices for natural gas and wholesale power have increased over 25% since then. Fuel costs were also higher because all of APS’ latest generation plant additions needed to serve customer growth are higher-cost natural gas-fired plants. Finally, Retail Fuel and Power Costs were higher because plant outage days were higher in the three-months and nine-months ended September 30, 2005 compared to the prior year periods.

     The amount of APS’ pretax PSA deferrals at September 30, 2005 was $143 million, including $80 million of PSA deferrals that are the subject of a pending surcharge application before the ACC. Although APS defers actual Retail Fuel and Power Costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval of periodic surcharge applications. APS estimates that its 2006 Retail Fuel and Power Costs will be approximately $834 million before income taxes. In its 2005 rate case filing, APS has requested the ACC to remove or increase the PSA’s $776.2 million annual limit on the recoverable amount of Retail Fuel and Power Costs through current base rates and the PSA. See “Power Supply Adjustor” in Note 5.

Operating Results — Three-month period ended September 30, 2005 compared with three-month period ended September 30, 2004

     Our consolidated net income for the three months ended September 30, 2005 was $104 million compared with $105 million for the prior-year period. The current quarter net income included $19 million (after-tax) from discontinued operations, which is primarily related to sales of commercial properties at SunCor. Income from continuing operations decreased $19 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

• Regulated Electricity Segment — Income from continuing operations decreased approximately $24 million primarily due to the regulatory disallowance of plant costs in accordance with the retail rate settlement. This negative factor was partially offset by a retail price increase effective April 1, 2005; PSA deferrals, net of higher fuel and purchased power costs; higher retail sales volumes due to customer growth; effects of weather on retail sales; and lower depreciation due to lower depreciation rates.

• Marketing and Trading Segment — Income from continuing operations increased approximately $3 million primarily due to higher mark-to-market gains on contracts for future delivery resulting from higher forward prices for wholesale electricity.

• Real Estate Segment — Income from continuing operations increased approximately $3 million primarily due to increased parcel and commercial property sales.

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Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Retail price increase effective April 1, 2005	$	27		$	16
PSA deferrals, net of higher fuel and purchased power costs		22			13
Higher retail sales volumes due to customer growth, excluding weather effects		21			13
Effects of weather on retail sales		16			10
Miscellaneous items, net		(5	)		(3	)
Net increase in regulated electricity segment gross margin		81			49
Marketing and trading segment gross margin:
Higher mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity		9			5
Miscellaneous items, net		(4	)		(2	)
Net increase in marketing and trading segment gross margin		5			3
Net increase in gross margin for regulated electricity and marketing and trading segments		86			52
Regulatory disallowance of plant costs, in accordance with the APS retail rate settlement		(143	)		(87	)
Higher real estate segment contribution primarily related to increased parcel and commercial property sales		5			3
Higher other income primarily due to increased interest income		6			4
Lower depreciation and amortization due to lower depreciation rates partially offset by higher depreciable assets		6			4
Miscellaneous items, net		1			5
Net decrease in income from continuing operations	$	(39	)		(19	)
Discontinued operations primarily related to real estate asset sales					18
Net decrease in net income				$	(1	)

Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $82 million higher for the three months ended September 30, 2005 compared with the prior-year period primarily as a result of:

• a $29 million increase in retail revenues related to customer growth, excluding weather effects;

• a $27 million increase in retail revenues due to a price increase effective April 1, 2005;

• a $21 million increase due to the effects of weather on retail sales;

48

• an $8 million increase in Off-System Sales primarily due to sales previously reported in the marketing and trading segment classified as of April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate settlement; and

• a $3 million decrease due to miscellaneous factors.

     Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $16 million higher for the three months ended September 30, 2005 compared with the prior-year period primarily as a result of:

• a $9 million increase in mark-to-market gains on forward contracts resulting from higher prices for wholesale electricity;

• a $7 million increase from higher prices for competitive retail sales in California;

• a $6 million increase in energy trading revenues on realized sales of electricity primarily due to higher delivered electricity prices; and

• a $6 million decrease from generation sales other than Native Load due to lower sales volumes and the elimination of sales previously reported in the marketing and trading segment classified as of April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate settlement.

     Real Estate Revenues

     Real estate revenues were $6 million higher for the three months ended September 30, 2005 compared with the prior-year period primarily due to increased parcel sales at SunCor.

Operating Results — Nine-month period ended September 30, 2005 compared with nine-month period ended September 30, 2004

     Our consolidated net income for the nine months ended September 30, 2005 was $155 million compared with $209 million for the prior-year period. The current year period net income included a loss from discontinued operations of $44 million (after-tax), which is primarily related to the pending sale and revenue and expenses related to Silverhawk (see discussion above), partially offset by sales of commercial properties at SunCor. Income from continuing operations decreased $10 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

• Regulated Electricity Segment — Income from continuing operations remained the same as the prior year period. The current period includes the regulatory disallowance of plant costs in accordance with the APS retail rate settlement; higher operations and maintenance costs primarily related to customer service, generation and benefit costs; and higher property taxes due to increased plant in service. These negative factors were offset by a retail price increase effective April 1, 2005; higher retail sales volumes due to customer growth; PSA deferrals, net of higher fuel and purchased power costs; the absence of regulatory asset amortization; effects of weather on retail sales and lower depreciation due to lower depreciation rates.

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• Marketing and Trading Segment — Income from continuing operations decreased approximately $4 million primarily due to lower realized margins on wholesale sales and competitive retail sales in California, partially offset by higher mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity.

• Real Estate Segment — Income from continuing operations increased approximately $16 million primarily due to increased parcel sales.

• Other Segment — Income from continuing operations decreased approximately $22 million primarily due to an after-tax gain related to the sale of a limited partnership interest in the Phoenix Suns recorded in the prior-year period.

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Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Retail price increase effective April 1, 2005	$	54		$	32
Higher retail sales volumes due to customer growth, excluding weather effects		41			25
PSA deferrals, net of higher fuel and purchased power costs		39			23
Effects of weather on retail sales		14			8
Miscellaneous items, net		(4	)		(2	)
Net increase in regulated electricity segment gross margin		144			86
Marketing and trading segment gross margin:
Higher mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity		9			5
Lower unit margins on competitive retail sales in California		(7	)		(4	)
Lower realized margins on wholesale sales primarily due to lower sales volumes and higher prices		(7	)		(4	)
Miscellaneous items, net		(1	)		—
Net decrease in marketing and trading segment gross margin		(6	)		(3	)
Net increase in gross margin for regulated electricity and marketing and trading segments		138			83
Regulatory disallowance of plant costs, in accordance with the APS retail rate settlement		(143	)		(87	)
Higher real estate segment contribution primarily related to increased parcel sales		27			16
Lower other income primarily due to sale of limited partnership interest in Phoenix Suns recorded in the prior-year period partially offset by higher interest income		(32	)		(19	)
Operations and maintenance increases primarily due to:
Customer service costs, including planned maintenance and demand side management costs		(17	)		(10	)
Generation costs, including planned maintenance		(14	)		(8	)
Benefit costs		(2	)		(1	)
Depreciation and amortization decreases primarily due to:
Absence of regulatory asset amortization		20			12
Lower depreciation rates partially offset by higher depreciable assets		13			8
Higher property taxes primarily due to increased plant in service		(10	)		(6	)
Miscellaneous items, net		5			2
Net decrease in income from continuing operations	$	(15	)		(10	)
Discontinued operations primarily related to the pending sale of Silverhawk (see discussion above) and real estate assets sales					(44	)
Net decrease in net income				$	(54	)

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     Regulated Electricity Segment Revenues

     Regulated electricity segment revenues were $143 million higher for the nine months ended September 30, 2005 compared with the prior-year period primarily as a result of:

• a $56 million increase in retail revenues related to customer growth, excluding weather effects;

• a $54 million increase in retail revenues due to a price increase effective April 1, 2005;

• a $20 million increase in Off-System Sales primarily due to sales previously reported in the marketing and trading segment classified as of April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate settlement;

• a $12 million increase in retail revenues related to weather; and

• a $1 million increase due to miscellaneous factors.

     Marketing and Trading Segment Revenues

     Marketing and trading segment revenues were $23 million lower for the nine months ended September 30, 2005 compared with the prior-year period primarily as a result of:

• a $25 million decrease from generation sales other than Native Load due to lower sales volumes and the elimination of sales previously reported in the marketing and trading segment classified as of April 2005 as sales in the regulated electricity segment in accordance with the APS retail rate settlement;

• a $10 million increase in mark-to-market gains on forward contracts resulting from higher prices for wholesale electricity;

• a $6 million decrease from lower volumes on competitive retail sales in California; and

• a $2 million decrease in energy trading revenues on realized sales of electricity primarily due to lower volumes.

     Real Estate Revenues

     Real estate revenues were $46 million higher for the nine months ended September 30, 2005 compared with the prior-year period primarily due to increased parcel sales at SunCor.

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LIQUIDITY AND CAPITAL RESOURCES

Capital Needs and Resources — Pinnacle West Consolidated

     Capital Expenditure Requirements

     The following table summarizes the actual capital expenditures for the nine months ended September 30, 2005 and estimated capital expenditures for the next three years.

CAPITAL EXPENDITURES
(dollars in millions)

	Nine Months Ended		Estimated for the Year Ended
	September 30,		December 31,
	2005		2005		2006		2007
APS
Delivery	$	313	$	418	$	442	$	492
Generation (a)		301		354		184		207
Other (b)		23		30		17		12
Subtotal		637		802		643		711
SunCor (c)		70		114		230		200
Other		5		12		9		2
Total	$	712	$	928	$	882	$	913

(a)	The nine months ended September 30, 2005 includes $185 million for the acquisition of the Sundance Plant in May 2005.
(b)	Primarily information systems and facilities projects.
(c)	Consists primarily of capital expenditures for land development and retail and office building construction reflected in “Real estate investments” on the Condensed Consolidated Statements of Cash Flows.

     Delivery capital expenditures are comprised of T&D 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 T&D lines and substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth. APS will begin major projects each year for the next several years, and expects to spend about $200 million on major transmission projects during the 2005 to 2007 time frame. These amounts are included in “APS-Delivery” in the table above. Completion of these projects is expected by at least 2008.

     Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants, the acquisition of the Sundance Plant and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines,

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boilers and environmental equipment. Generation also includes nuclear fuel expenditures of approximately $30 to $35 million annually for 2005 through 2007.

     Replacement of the steam generators in Palo Verde Unit 2 was completed during the fall 2003 outage at a cost to APS of approximately $70 million. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. These generators will be installed in Unit 1 (scheduled completion in December 2005) and Unit 3 (scheduled completion in the fall of 2007). Our portion of steam generator expenditures for Units 1 and 3 is approximately $140 million, which will be spent through 2008. In 2005 through 2007, approximately $95 million of the costs for steam generator replacements at Units 1 and 3 are included in the generation capital expenditures table above and will be funded with internally-generated cash or external financings.

Contractual Obligations

     Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2004 Form 10-K with the exception of our aggregate:

• purchased power and fuel commitments, which increased from approximately $855 million at December 31, 2004 to $1.1 billion at September 30, 2005 primarily due to increased commitments for the years 2005 through 2007; and

• nuclear decommissioning funding requirements, which increased from approximately $201 million at December 31, 2004 to $386 million at September 30, 2005 for the years 2005 and thereafter as a result of the 2004 Settlement Agreement.

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

     Off-Balance Sheet Arrangements

     In 1986, APS entered into agreements with three separate VIE lessors in order to sell and lease back interests in Palo Verde Unit 2. The leases are accounted for as operating leases in accordance with GAAP. We are not the primary beneficiary of the Palo Verde VIEs and, accordingly, do not consolidate them.

     APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of September 30, 2005, APS would have been required to assume approximately $245 million of debt and pay the equity participants approximately $191 million.

     Guarantees and Letters of Credit

     We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to

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these obligations. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 15 for additional information regarding guarantees and letters of credit.

     Credit Ratings

     The ratings of securities of Pinnacle West and APS as of November 7, 2005 are shown below and are considered to be “investment-grade” ratings. 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 those companies’ cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).

	Moody’s	Standard & Poor’s
Pinnacle West
Senior unsecured	Baa2	BBB-
Commercial paper	P-2	A-2
Outlook	Stable	Stable
APS
Senior unsecured	Baa1	BBB
Secured lease obligation bonds	Baa1	BBB
Commercial paper	P-2	A-2
Outlook	Stable	Stable

     Debt Provisions

     Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include a debt-to-total-capitalization ratio and 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. These covenants require that the ratio of debt to total capitalization cannot exceed 65% for the Company and for APS. At September 30, 2005, the ratio was approximately 51% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for the Company and for APS. The interest coverage is approximately 3.6 times under the Company’s bank financing agreements and 3.5 times under APS’ bank financing agreements as of September 30, 2005. 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.

     Neither Pinnacle West’s nor APS’ financing agreements contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, Pinnacle West and/or APS may be subject to increased interest costs under certain financing agreements.

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     All of Pinnacle West’s bank 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 other 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 other agreements. Pinnacle West’s and APS’ credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in financial condition or financial prospects, except that Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings equal to outstanding commercial paper amounts.

     See Note 4 for further discussions.

Capital Needs and Resources — By Company

     Pinnacle West (Parent Company)

     Our primary cash needs are for dividends to our shareholders and principal and interest payments on our long-term debt. The level of our common dividends and future dividend growth will be dependent on a number of factors including, but not limited to, payout ratio trends, free cash flow and financial market conditions.

     Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. As discussed in Note 5 under “ACC Financing Order,” APS must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce its common equity below that threshold. As defined in the Financing Order, 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 September 30, 2005, APS’ common equity ratio, as defined, was approximately 54%.

     Pinnacle West sponsors a qualified pension plan for the employees of Pinnacle West and our subsidiaries. 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 the fund assets and our pension obligation. The assets in the plan are comprised of common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $35 million in 2004. Our required 2005 pension contribution of approximately $53 million has been made for the year. We expect to contribute approximately $37 million to other postretirement benefit plans in 2005 and have contributed approximately $28 million of that amount through October 2005. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 96% of both plans.

     On May 2, 2005, Pinnacle West redeemed at par all of its $165 million Floating Rate Senior Notes due November 1, 2005. The Company used cash on hand to redeem the notes.

     On May 2, 2005, Pinnacle West issued 6,095,000 shares of its common stock at an offering price of $42 per share, resulting in net proceeds of approximately $248 million. Pinnacle West used the net proceeds for general corporate purposes, including making capital contributions to APS, which, in turn, used such funds to pay a portion of the approximately $190 million purchase price to acquire the Sundance Plant and for other capital expenditures incurred to meet the growing needs of APS’ service territory.

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     On October 19, 2005, the Pinnacle West Board of Directors declared a quarterly dividend of $0.50 per share of common stock, payable on December 1, 2005, to shareholders of record on November 1, 2005.

     See “Equity Infusion Notice” in Note 5 for information regarding the ACC approval of Pinnacle West’s infusion of at least $450 million of equity into APS.

     APS

     APS’ capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See “ACC Financing Order” in Note 5 for a discussion of the $500 million loan from APS to Pinnacle West Energy authorized by the ACC pursuant to the Financing Order. This loan was repaid on April 11, 2005.

     APS pays for its capital requirements with cash from operations and, to the extent necessary, external financings. APS has historically paid its dividends to Pinnacle West with cash from operations. See “Pinnacle West (Parent Company)” above for a discussion of the common equity ratio that APS must maintain in order to pay dividends to Pinnacle West.

     On January 15, 2005, APS repaid its $100 million 6.25% Notes due 2005. APS used cash on hand to redeem these notes.

     On March 1, 2005, Maricopa County, Arizona Pollution Control Corporation issued $164 million of variable interest rate pollution control bonds, 2005 Series A-E, due 2029. The bonds were issued to refinance $164 million of outstanding pollution control bonds. The Series A-E bonds are payable solely from revenues obtained from APS pursuant to a loan agreement between APS and Maricopa County, Arizona Pollution Control Corporation. These bonds are classified as long-term debt on our Condensed Balance Sheets.

     On August 1, 2005, APS repaid $300 million of its 7.625% Notes due 2005. APS used cash on hand to repay these notes.

     On August 22, 2005, APS issued $250 million of 5.50% Senior Unsecured Notes due September 1, 2035. A portion of the net proceeds from the sale of the notes was used for general corporate purposes and, on October 3, 2005, APS used the balance of the proceeds, along with cash on hand, to fund the $500 million that it was obligated to transfer to Pinnacle West Energy in connection with APS’ acquisition of the PWEC Dedicated Assets. See “Related Party Transactions” in Note S-5 for information regarding the $500 million intercompany payable to Pinnacle West Energy at September 30, 2005. APS satisfied this obligation to Pinnacle West Energy on October 3, 2005.

     Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.

     See “Deferred Fuel and Purchased Power Costs” above and “Power Supply Adjustor” in Note 5 for information regarding the PSA approved by the ACC. Although APS defers actual Retail Fuel and Power Costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval of periodic surcharge applications. See “Power Supply Adjustor” in Note 5.

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     See “Cash Flow Hedges” in Note 10 for information related to increased collateral provided to us by counterparties.

     Pinnacle West Energy

     Pinnacle West Energy expects minimal capital expenditures over the next three years.

     See “ACC Financing Order” in Note 5 for a discussion of the $500 million loan from APS to Pinnacle West Energy authorized by the ACC pursuant to the Financing Order. On April 11, 2005 Pinnacle West Energy issued $500 million Floating Rate Senior Notes due April 1, 2007. Pinnacle West has unconditionally guaranteed these notes. Pinnacle West Energy used the proceeds of this issuance to repay the APS loan. On October 3, 2005, Pinnacle West Energy repaid the Floating Rate Senior Notes due April 1, 2007 with $500 million received from APS in connection with the transfer of the PWEC Dedicated Assets.

     See Note 17 of Notes to Condensed Consolidated Financial Statements above for a discussion of the pending sale of our 75% ownership interest in Silverhawk.

     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 nine months ended September 30, 2005 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.

     El Dorado expects minimal capital requirements over the next three years and intends to focus on prudently realizing the value of its existing investments.

     APS Energy Services expects minimal capital expenditures over the next three years.

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 and 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 2004 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2004 Form 10-K for further details about our critical accounting policies.

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PINNACLE WEST CONSOLIDATED — FACTORS AFFECTING
OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

     General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. These revenues are affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity rates and tariffs and variations in weather from period to period. Competitive sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition.

     Customer and Sales Growth The customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory averaged about 3.4% a year for the three years 2002 through 2004; we currently expect customer growth to average about 4% per year from 2005 to 2007. We currently estimate that total retail electricity sales in kilowatt-hours will grow 5% on average, from 2005 through 2007, before the effects of weather variations. Customer growth for the nine-month period ended September 30, 2005 compared with the prior-year period was 4.2%.

     Actual sales growth, excluding weather-related variations, may differ from our projections as a result of numerous factors, such as economic conditions, customer growth and usage patterns. Our experience indicates that a reasonable range of variation in our kilowatt-hour sales projection attributable to such economic factors can result in increases or decreases in annual net income of up to $10 million.

     Weather In forecasting retail sales growth, we assume normal weather patterns based on historical data. Historical extreme weather variations have resulted in annual variations in net income in excess of $20 million. However, our experience indicates that the more typical variations from normal weather can result in increases or decreases in annual net income of up to $10 million.

     Retail Rate Matters See “APS 2003 Rate Case” in Note 5 for a discussion of the ACC’s order in APS’ 2003 rate case and “Power Supply Adjustor” for information regarding APS’ PSA, including APS’ application to the ACC requesting recovery of $80 million in deferred Retail Fuel and Power Costs under the PSA. See “APS 2005 Rate Case” in Note 5 for information regarding the general rate case APS filed with the ACC on November 4, 2005, which includes a request that the ACC remove or increase the PSA’s $776.2 million annual limit on the Retail Fuel and Power Costs that APS can recover through its current base rates and the PSA. APS estimates that its Retail Fuel and Power Costs in 2006 will be approximately $834 million, before income taxes, and that it will exceed the $776.2 million limit in the fourth quarter of that year.

     Fuel and Purchased Power Costs Fuel and purchased power costs 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, variances in deferrals and amortization of fuel and purchased power beginning on April 1, 2005 and our hedging program for managing such costs. See “Power Supply Adjustor” in Note 5 for information regarding the PSA approved by the ACC. See “Natural Gas Supply” in Note 12 for more information on fuel costs.

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     Wholesale Power Market Conditions The marketing and trading division focuses primarily on managing APS’ risks relating to purchased power and fuel costs in connection with its costs of serving Native Load customer demand. The marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market.

Other Factors Affecting Financial Results

     Operations and Maintenance Expenses Operations and maintenance expenses are impacted by growth, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors.

     Depreciation and Amortization Expenses Depreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction or acquisition, changes in depreciation and amortization rates (see Note 5), and changes in regulatory asset amortization. See Note 17 for information on the pending sale of Silverhawk. See Note 4 for information on APS’ acquisition of the Sundance Plant in 2005 and “Requests for Proposals” in Part II, Item 5 of this report for more information on requests for proposals to acquire additional long-term resources in 2006 and 2007.

     Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. The average property tax rate for APS, which currently owns the majority of our property, was 9.2% of assessed value for 2004 and 9.3% for 2003. We expect property taxes to increase as new power plants, the acquisition of the Sundance Plant and our additions to transmission and distribution facilities into the property tax base.

     Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our 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. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs.

     Retail Competition Although some very limited retail competition existed in Arizona in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to APS’ customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter APS’ service territory, or APS Energy Services will be able to serve other areas of Arizona.

     Subsidiaries In the case of SunCor, efforts to accelerate sales activities in 2003-2005 were successful. A portion of these sales have been, and additional amounts may be required to be, reported as discontinued operations on our Condensed Consolidated Statements of Income. SunCor’s net income was $56 million in 2003 and $45 million in 2004. See Note 17 for further discussion. We anticipate SunCor’s earnings contributions in 2005 will be approximately $50 million after income taxes. We currently estimate that SunCor's earnings will be between $40 million and $50 million after taxes in each of 2006 and 2007.

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     APS Energy Services’ and El Dorado’s historical results are not indicative of future performance. Both are expected to be minor for the foreseeable future.

     General Our financial results may be affected by a number of broad factors. See “Forward-Looking Statements” for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate.

Market Risks

     Our operations include managing market risks related to changes in interest rates, commodity prices and investments held by our nuclear decommissioning trust fund.

     Interest Rate and Equity Risk

     Our major financial market risk exposure is to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The nuclear decommissioning fund also has risk associated with changing market value of equity 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, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity instruments that qualify as derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. Our ERMC, consisting of officers and key management personnel, oversees company-wide energy risk management activities and monitors the results of marketing and trading activities to ensure compliance with our stated energy risk management and trading policies. As part of our risk management program, we use such instruments to hedge purchases and sales of electricity, fuels and emissions allowances and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodities. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

     The mark-to-market value of derivative instruments related to our risk management and trading activities are presented in two categories consistent with our business segments:

• Regulated Electricity — non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for APS’ Native Load requirements of our regulated electricity business segment; and

• Marketing and Trading — non-trading and trading derivative instruments of our competitive business segment.

     The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions for the nine months ended September 30, 2005 and 2004 (dollars in millions):

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	Nine Months Ended						Nine Months Ended
	September 30, 2005						September 30, 2004
	Regulated			Marketing			Regulated			Marketing
	Electricity			and Trading			Electricity			and Trading
Mark-to-market of net positions at beginning of period	$	33		$	107		$	—		$	69
Recognized in earnings:
Change in mark-to-market gains for future period deliveries		15			24			12			16
Mark-to-market (gains)/losses realized during the period		(6	)		(3	)		6			(10	)
Recognized in OCI:
Change in mark-to-market gains for future period deliveries (a)		400			125			68			33
Mark-to-market gains realized during the period		(38	)		(19	)		(18	)		(4	)
Deferred as a Regulatory Liability		29			—			—			—
Change in valuation techniques		—			—			—			2
Mark-to-market of net positions at end of period	$	433		$	234		$	68		$	106

(a) The increase in regulated mark-to-market recorded in OCI is due primarily to increases in forward natural gas prices.

     The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at September 30, 2005 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2004 Form 10-K for more discussion of our valuation methods.

Regulated Electricity

													Total
													fair
Source of Fair Value	2005			2006			2007			2008			value
Prices actively quoted	$	73		$	157		$	45		$	20		$	295
Prices provided by other external sources		—			78			61			3			142
Prices based on models and other valuation methods		(1	)		(1	)		(1	)		(1	)		(4	)
Total by maturity	$	72		$	234		$	105		$	22		$	433

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Marketing and Trading

																		Total
																		fair
Source of Fair Value	2005			2006			2007			2008		2009			Thereafter			value
Prices actively quoted	$	38		$	2		$	—		$	—	$	—		$	—		$	40
Prices provided by other external sources		—			116			91			22		(1	)		3			231
Prices based on models and other valuation methods		(3	)		(34	)		(13	)		16		—			(3	)		(37	)
Total by maturity	$	35		$	84		$	78		$	38	$	(1	)	$	—		$	234

     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 September 30, 2005 and December 31, 2004 (dollars in millions).

	September 30, 2005						December 31, 2004
	Gain (Loss)						Gain (Loss)
	Price Up			Price Down			Price Up			Price Down
	10%			10%			10%			10%
Commodity
Mark-to-market changes reported in earnings (a):
Electricity	$	(1	)	$	—		$	(4	)	$	4
Natural gas		—			—			2			(2	)
Other		1			(1	)		1			(1	)
Mark-to-market changes reported in OCI (b):
Electricity		53			(55	)		35			(35	)
Natural gas		114			(114	)		43			(43	)
Total	$	167		$	(170	)	$	77		$	(77	)

(a)	These contracts are primarily structured sales activities hedged with a portfolio of forward purchases that protects the economic value of the sales transactions.
(b)	These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

     We are exposed to losses in the event of non-performance or non-payment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 10% of Pinnacle West’s $1.5 billion of risk management and trading assets as of September 30, 2005. See Note 1, “Derivative

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Accounting” in Item 8 of our 2004 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.

ARIZONA PUBLIC SERVICE COMPANY — RESULTS OF OPERATIONS

General

     Throughout the following explanations of our results of operations, we refer to “gross margin.” Gross margin refers to electric operating revenues less purchased power and fuel costs. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.4 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses. In addition, we have reclassified certain prior-period amounts to conform to our current-period presentation.

Deferred Fuel and Purchased Power Costs

     APS’ retail rate settlement became effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund Retail Fuel and Power Costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual Retail Fuel and Power Costs and the amount of such costs currently included in base rates. Actual Retail Fuel and Power Costs are higher than prior periods primarily due to higher fuel prices. The current base rate for Retail Fuel and Power Costs is based on 2003 price levels, and spot prices for natural gas and wholesale power have increased over 25% since then. Fuel costs were also higher because all of APS’ latest generation plant additions needed to serve customer growth are higher-cost natural gas fired plants. Finally, Retail Fuel and Power Costs were higher because plant outage days were higher in the three months and nine months ended September 30, 2005 compared to the prior year periods.

     The amount of APS’ pretax PSA deferrals at September 30, 2005 was $143 million, including $80 million of PSA deferrals that are the subject of a pending surcharge application before the ACC. Although APS defers actual Retail Fuel and Power Costs on a current basis, APS’ recovery of the deferrals from its ratepayers is subject to annual PSA adjustments and ACC approval of periodic surcharge applications. APS estimates that its 2006 Retail Fuel and Power Costs will be approximately $834 million before income taxes. In its 2005 rate case filing, APS has requested the ACC to remove or increase the PSA’s $776.2 million annual limit on the recoverable amount of Retail Fuel and Power Costs through current base rates and the PSA. See “Power Supply Adjustor” in Note 5.

Operating Results — Three-month period ended September 30, 2005 compared with three-month period ended September 30, 2004

     APS’ net income for the three months ended September 30, 2005 was $61 million compared with $95 million for the prior-year period. The $34 million decrease was primarily due to the regulatory disallowance of plant costs in accordance with the retail rate settlement. This negative factor was partially offset by a retail price increase effective April 1, 2005; PSA deferrals, net of higher fuel and purchased power costs; higher retail sales volumes due to customer growth; effects of weather on retail sales; and lower depreciation due to lower depreciation rates.

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     Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Gross margin:
PSA deferrals, net of higher fuel and purchased power costs	$	41		$	25
Retail price increase effective April 1, 2005		27			16
Higher retail sales volumes due to customer growth, excluding weather effects		21			13
Effects of weather on retail sales		16			10
Lower mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity		(10	)		(6	)
Miscellaneous items, net		(7	)		(4	)
Net increase gross margin		88			54
Regulatory disallowance of plant costs, in accordance with the retail rate settlement		(143	)		(87	)
Operations and maintenance expensed increased primarily due to higher generation and customer service costs partially offset by decreased benefit costs		(6	)		(4	)
Lower depreciation and amortization due to lower depreciation rates partially offset by higher depreciable assets		1			1
Miscellaneous items, net		(4	)		2
Net decrease in net income	$	(64	)	$	(34	)

Regulated Electricity Revenues

     Regulated electricity revenues were $80 million higher for the three months ended September 30, 2005 compared with the prior-year period primarily as a result of:

• a $29 million increase in retail revenues related to customer growth, excluding weather effects;

• a $27 million increase in retail revenues due to a price increase effective April 1, 2005;

• a $21 million increase due to effects of weather on retail sales;

• an $8 million increase in Off-System Sales primarily due to sales previously reported in marketing and trading now classified as sales in regulated electricity in accordance with the retail rate settlement; and

• a $5 million decrease due to miscellaneous factors.

     Marketing and Trading Revenues

     Marketing and trading revenues were $33 million lower for the three months ended September 30, 2005 compared with the prior-year period primarily as a result of:

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• a $15 million decrease on future mark-to-market gains due to higher prices;

• a $12 million decrease in energy trading revenues on realized sales of electricity primarily due to lower delivered electricity prices and lower sales volumes; and

• a $6 million decrease in revenues from Off-System Sales primarily due to lower sales volumes and sales previously reported in marketing and trading now classified as sales in the regulated electricity in accordance with the retail rate settlement.

Operating Results — Nine-month period ended September 30, 2005 compared with nine-month period ended September 30, 2004

     APS’ net income for the nine months ended September 30, 2005 was $152 million compared with $185 million for the prior-year period. The $33 million decrease was primarily due to the regulatory disallowance of plant costs in accordance with the retail rate settlement, higher operations and maintenance costs primarily related to generation, customer service, and benefit costs, and higher property taxes due to increased plant in service. These negative factors were partially offset by a retail price increase effective April 1, 2005; higher retail sales volumes due to customer growth; PSA deferrals, net of higher fuel and purchased power costs; the absence of regulatory asset amortization; effects of weather on retail sales; and lower depreciation due to lower depreciation rates.

     Additional details on the major factors that increased (decreased) net income are contained in the following table (dollars in millions):

	Increase (Decrease)
	Pretax			After Tax
Gross margin:
Retail price increase effective April 1, 2005	$	54		$	32
Higher retail sales volumes due to customer growth, excluding weather effects		41			25
PSA deferrals, net of higher fuel and purchased power costs		18			11
Effects of weather on retail sales		14			8
Lower mark-to-market gains on contracts for future delivery due to higher forward prices for wholesale electricity		(14	)		(8	)
Miscellaneous items, net		2			1
Net increase in gross margin		115			69
Regulatory disallowance of plant costs, in accordance with the retail rate settlement		(143	)		(87	)
Operations and maintenance increases primarily due to:
Generation costs, including planned maintenance		(14	)		(8	)
Customer service costs, including planned maintenance and demand side management costs		(17	)		(10	)
Benefit costs		(3	)		(2	)
Depreciation and amortization decreases primarily due to:
Absence of regulatory asset amortization		20			12
Higher depreciable assets partially offset by lower depreciation rates (see Note 5)		(2	)		(1	)
Higher property taxes due to increased plant in service		(11	)		(6	)
Net decrease in net income	$	(55	)	$	(33	)

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     Regulated Electricity Revenues

     Regulated electricity revenues were $137 million higher for the nine months ended September 30, 2005 compared with the prior-year period primarily as a result of:

• a $56 million increase in retail revenues related to customer growth, excluding weather effects;

• a $54 million increase in retail revenues due to a price increase effective April 1, 2005 ;

• a $20 million increase in Off-System Sales primarily due to sales previously reported in marketing and trading now classified as sales in regulated electricity in accordance with the retail rate settlement;

• a $12 million increase in retail revenues related to weather; and

• a $5 million decrease due to miscellaneous factors.

     Marketing and Trading Revenues

     Marketing and trading revenues were $70 million lower for the nine months ended September 30, 2005 compared with the prior-year period primarily as a result of:

• a $31 million decrease in energy trading revenues on realized sales of electricity primarily due to lower delivered electricity prices and lower volumes;

• a $25 million decrease in revenues from Off-System Sales primarily due to lower sales volumes and sales previously reported in marketing and trading now classified as sales in regulated electricity in accordance with the retail rate settlement; and

• a $14 million decrease on future mark-to-market gains due to higher prices.

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ARIZONA PUBLIC SERVICE COMPANY — LIQUIDITY AND CAPITAL RESOURCES

     Contractual Obligations

     APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2004 Form 10-K with the exception of our aggregate:

• purchased power and fuel commitments, which increased from approximately $948 million at December 31, 2004 to $1.1 billion at September 30, 2005 primarily due to increased commitments for the years 2005 through 2007; and

• nuclear decommissioning funding requirements, which increased from approximately $201 million at December 31, 2004 to $386 million at September 30, 2005 for the years 2005 and thereafter as a result of the 2004 Settlement Agreement.

     See Note S-1 for a list of APS’ payments due on total long-term debt and capitalized lease requirements.

RISK FACTORS

     Exhibit 99.1 and Exhibit 99.2, which are hereby incorporated by reference, contain a discussion of risk factors affecting Pinnacle West and APS, respectively.

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 Exhibits 99.1 and 99.2 to this report, these factors include, but are not limited to:

• state and federal regulatory and legislative decisions and actions, including the outcome and timing of the rate case filed with the ACC on November 4, 2005;

• the timely recovery of PSA deferrals and our assumption that the ACC will address the $776.2 million annual limit on the amount of Retail Fuel and Power Costs that can be reflected in existing rates and the PSA and our assumption that currently effective ACC orders remain effective until changed or superseded by the ACC, as described herein;

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

• the outcome of regulatory, legislative and judicial proceedings relating to the restructuring;

• market prices for electricity and natural gas;

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• power plant performance and outages;

• transmission outages and constraints;

• weather variations affecting local and regional customer energy usage;

• customer growth and energy usage;

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

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

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

• our ability to compete successfully outside traditional regulated markets (including the wholesale market);

• the performance of our marketing and trading activities due to volatile market liquidity and any deteriorating counterparty credit and the use of derivative contracts in our business (including the interpretation of the subjective and complex accounting rules related to these contracts);

• changes in accounting principles generally accepted in the United States of America and the interpretation of those principles;

• the performance of the stock market and the changing interest rate environment, which affect the amount of required contributions to Pinnacle West’s pension plan and APS’ nuclear decommissioning trust funds, as well as the reported costs of providing pension and other postretirement benefits;

• technological developments in the electric industry;

• the strength of the real estate market in SunCor’s market areas, which include Arizona, Idaho, New Mexico and Utah; and

• other uncertainties, all of which are difficult to predict and many of which are beyond the control of Pinnacle West and APS.

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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.

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Item 4. CONTROLS AND PROCEDURES

     (a) Disclosure Controls and Procedures

     The term “disclosure controls and procedures” means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Securities Exchange Act of 1934 (the “Exchange Act”) (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to a company’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

     Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of September 30, 2005. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

     APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of September 30, 2005. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.

     (b) Changes In Internal Control Over Financial Reporting

     The term “internal control over financial reporting” (defined in SEC Rule 13a-15(f)) refers to the process of a company that is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

     No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended September 30, 2005 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

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Part II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

     See Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report in regard to pending or threatened litigation or other disputes.

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 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of regulatory developments.

Environmental Matters

     See “Environmental Matters — Superfund” in Note 12 of Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of a Superfund site.

Federal Energy Legislation

     On August 8, 2005, the President signed the Energy Policy Act of 2005 into law. Due to its recent enactment and because many provisions require implementing regulations, the Company is unable to predict the impact of the Act on its operations.

Requests for Proposals

     APS continually assesses its need for additional capacity resources to assure system reliability. Under the terms of the 2004 Settlement Agreement, APS committed to seek proposals from the competitive wholesale market for filling its future resource needs. The current reliability RFP identifies the amount of capacity and energy needed to reliably meet expected customer demands and sought proposals for at least 1,000 MW of new generating capacity for 2007 and beyond. Winning bidders have been notified. APS has entered into contracts for more than 500 MW of capacity and expects to finalize the remainder of the contracts by mid-November 2005.

     APS also has in process a renewable RFP seeking at least 100 MW of renewable capacity with a capability of producing at least 250,000 MWH annually. In accordance with the terms of the 2004 Settlement Agreement, power must be deliverable to the APS transmission system and its pricing must not exceed 125% of conventional resource alternatives. APS has entered into MOUs for several projects. At the ACC Open Meeting on November 8, 2005, the ACC approved APS’ acquisition of out-of-state renewable resources. The ACC also ordered APS to work with the ACC staff to evaluate two in-state projects and report back within two months.

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Item 6. EXHIBITS

(a) Exhibits

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Pinnacle West	Pinnacle West Risk Factors
99.2	APS	APS Risk Factors
99.3	Pinnacle West	Reconciliation of Operating Income to Gross Margin

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Exhibit No.	Registrant(s)	Description
99.4	APS	Reconciliation of Operating Income to Gross Margin

     In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation §229.10(d) by reference to the filings set forth below:

Exhibit				Date
No.	Registrant(s)	Description	Previously Filed as Exhibit1	Effective
3.1	Pinnacle West	Articles of Incorporation, restated as of July 29, 1988	19.1 to Pinnacle West’s September 1988 Form 10-Q Report, File No. 1-8962	11-14-88
3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of June 23, 2004	3.1 to Pinnacle West’s June 30, 2004 Form 10-Q Report, File No. 1-8962	8-9-04
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.

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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: November 9, 2005	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		Executive Vice President and Chief
		Financial Officer
		(Principal Financial Officer
		and Officer Duly Authorized to sign this Report)
	ARIZONA PUBLIC SERVICE COMPANY
	(Registrant)
Dated: November 9, 2005	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		Executive Vice President and Chief
		Financial Officer
		(Principal Financial Officer and
		Officer Duly Authorized to sign this Report)

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Exhibit Index

Exhibit No.	Registrant(s)	Description
12.1	Pinnacle West	Ratio of Earnings to Fixed Charges
12.2	APS	Ratio of Earnings to Fixed Charges
31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.2	Pinnacle West	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.3	APS	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
31.4	APS	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	APS	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1	Pinnacle West	Pinnacle West Risk Factors
99.2	APS	APS Risk Factors
99.3	Pinnacle West	Reconciliation of Operating Income to Gross Margin
99.4	APS	Reconciliation of Operating Income to Gross Margin

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