Pinnacle West Capital 10Q 2007 Q1 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2007


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

For the transition period from to


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


	ARIZONA PUBLIC SERVICE COMPANY
1-4473	(an Arizona corporation)	86-0011170
	400 North Fifth Street, P.O. Box 53999
	Phoenix, Arizona 85072-3999
	(602) 250-1000

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


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

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

PINNACLE WEST CAPITAL CORPORATION

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

ARIZONA PUBLIC SERVICE COMPANY

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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


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

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


PINNACLE WEST CAPITAL CORPORATION		Number of shares of common stock, no par value, outstanding as of May 3, 2007: 100,237,583
ARIZONA PUBLIC SERVICE COMPANY		Number of shares of common stock, $2.50 par value, outstanding as of May 3, 2007: 71,264,947

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

This combined Form 10-Q is separately filed by Pinnacle West Capital Corporation and Arizona Public Service Company. Each registrant is filing on its own behalf all of the information contained in this Form 10-Q that relates to such registrant and, where required, its subsidiaries. Except as stated in the preceding sentence, neither registrant is filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.

GLOSSARY

ACC – Arizona Corporation Commission

ADEQ – Arizona Department of Environmental Quality

ALJ – Administrative Law Judge

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

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

Clean Air Act – Clean Air Act, as amended

Company – Pinnacle West Capital Corporation

DOE – United States Department of Energy

EITF – FASB’s Emerging Issues Task Force

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

EPA – United States Environmental Protection Agency

ERMC – Energy Risk Management Committee

FASB – Financial Accounting Standards Board

FERC – United States Federal Energy Regulatory Commission

FIN – FASB Interpretation Number

Fitch – Fitch, Inc.

Four Corners – Four Corners Power Plant

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

IRS – United States Internal Revenue Service

kWh – kilowatt-hour, one thousand watts per hour

Moody’s – Moody’s Investors Service

MWh – megawatt-hour, one million watts per hour

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

Note – a Note to Pinnacle West’s Condensed Consolidated Financial Statements in Item 1 of this report

NRC – United States Nuclear Regulatory Commission

OCI – other comprehensive income

Off-System Sales – sales of electricity from generation owned or contracted by the Company that is over and above the amount required to serve APS’ retail customers and traditional wholesale contracts

Palo Verde – Palo Verde Nuclear Generating Station

Pinnacle West – Pinnacle West Capital Corporation, the Company

Pinnacle West Energy – Pinnacle West Energy Corporation, a subsidiary of the Company, dissolved as of August 31, 2006

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

PRP – potentially responsible parties under Superfund

PSA – power supply adjustor

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

SEC – United States Securities and Exchange Commission

SFAS – Statement of Financial Accounting Standards

Silverhawk – Silverhawk Power Station

Standard & Poor’s – Standard & Poor’s Corporation

SunCor – SunCor Development Company, a subsidiary of the Company

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

Superfund – Comprehensive Environmental Response, Compensation and Liability Act

2006 Form 10-K – Pinnacle West/APS Annual Report on Form 10-K for the fiscal year ended December 31, 2006

VIE – variable interest entity

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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


	Three Months Ended
	March 31,
	2007			2006
OPERATING REVENUES
Regulated electricity segment	$	536,051		$	466,126
Real estate segment		77,250			107,854
Marketing and trading		72,471			85,002
Other revenues		9,363			11,224

Total		695,135			670,206

OPERATING EXPENSES
Regulated electricity segment fuel and purchased power		203,353			157,395
Real estate segment operations		61,443			71,330
Marketing and trading fuel and purchased power		57,944			74,175
Operations and maintenance		171,578			178,427
Depreciation and amortization		89,621			87,621
Taxes other than income taxes		34,719			35,573
Other expenses		8,488			8,522

Total		627,146			613,043

OPERATING INCOME		67,989			57,163

OTHER
Allowance for equity funds used during construction		4,444			3,801
Other income (Note 14)		4,512			5,467
Other expense (Note 14)		(6,353	)		(4,541	)

Total		2,603			4,727

INTEREST EXPENSE
Interest charges		50,992			47,526
Capitalized interest		(4,807	)		(4,024	)

Total		46,185			43,502

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		24,407			18,388
INCOME TAXES		8,609			6,793

INCOME FROM CONTINUING OPERATIONS		15,798			11,595
INCOME FROM DISCONTINUED OPERATIONS
Net of income tax expense of $479 and $557 (Note 17)		732			860

NET INCOME	$	16,530		$	12,455

WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – BASIC		100,045			99,115
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING – DILUTED		100,622			99,449

EARNINGS PER WEIGHTED-AVERAGE COMMON SHARE OUTSTANDING
Income from continuing operations – basic	$	0.16		$	0.12
Net income – basic		0.17			0.13
Income from continuing operations – diluted		0.16			0.12
Net income – diluted		0.16			0.13
DIVIDENDS DECLARED PER SHARE	$	0.525		$	1.00

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

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


	March 31,			December 31,
	2007			2006
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	121,253		$	87,210
Investment in debt securities		—			32,700
Customer and other receivables		371,467			501,628
Allowance for doubtful accounts		(5,165	)		(5,597	)
Materials and supplies (at average cost)		137,357			125,802
Fossil fuel (at average cost)		24,856			21,973
Deferred income taxes		—			982
Assets from risk management and trading activities (Note 10)		245,458			641,040
Assets held for sale		16,714			—
Other current assets		59,162			68,924

Total current assets		971,102			1,474,662


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

Total investments and other assets		1,145,855			1,148,378


PROPERTY, PLANT AND EQUIPMENT
Plant in service and held for future use		11,257,974			11,154,919
Less accumulated depreciation and amortization		3,852,033			3,797,475

Net		7,405,941			7,357,444
Construction work in progress		420,598			368,284
Intangible assets, net of accumulated amortization		90,251			96,100
Nuclear fuel, net of accumulated amortization		69,539			60,100

Total property, plant and equipment		7,986,329			7,881,928


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

Total deferred debits		905,671			950,975


TOTAL ASSETS	$	11,008,957		$	11,455,943

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

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


	March 31,			December 31,
	2007			2006
LIABILITIES AND COMMON STOCK EQUITY

CURRENT LIABILITIES
Accounts payable	$	226,649		$	346,047
Accrued taxes (Note 8)		317,250			263,935
Accrued interest		43,003			48,746
Short-term borrowings		71,050			35,750
Current maturities of long-term debt		61,428			1,596
Customer deposits		72,382			70,168
Deferred income taxes		10,744			—
Liabilities from risk management and trading activities (Note 10)		148,827			558,195
Other current liabilities		139,552			134,123

Total current liabilities		1,090,885			1,458,560


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


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

Total deferred credits and other		3,282,152			3,318,634


COMMITMENTS AND CONTINGENCIES (NOTES 5, 8, 12, 13 and 15)

COMMON STOCK EQUITY Common stock, no par value		2,121,070			2,114,550
Treasury stock		(750	)		(449	)

Total common stock		2,120,320			2,114,101

Accumulated other comprehensive income (loss) (Note 11):
Pension and other postretirement benefits		(19,110	)		(19,263	)
Derivative instruments		66,606			31,531

Total accumulated other comprehensive income		47,496			12,268

Retained earnings		1,281,106			1,319,747

Total common stock equity		3,448,922			3,446,116


TOTAL LIABILITIES AND COMMON STOCK EQUITY	$	11,008,957		$	11,455,943

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

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


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

Net cash flow provided by operating activities		214,581			3,057


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

Net cash flow provided by (used for) investing activities		(184,001	)		31,697


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

Net cash flow provided by financing activities		3,463			126,098


NET INCREASE IN CASH AND CASH EQUIVALENTS		34,043			160,852

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		87,210			154,003


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	121,253		$	314,855

Supplemental disclosure of cash flow information
Cash paid during the period for:
Income taxes paid, net of refunds	$	38,980		$	(40	)
Interest paid, net of amounts capitalized	$	50,703		$	25,526

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

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Consolidation and Nature of Operations

The unaudited condensed consolidated financial statements include the accounts of Pinnacle West and our subsidiaries: APS, Pinnacle West Energy (dissolved as of August 31, 2006), APS Energy Services, SunCor, El Dorado and Pinnacle West Marketing & Trading. All significant intercompany accounts and transactions between the consolidated companies have been eliminated. Our accounting records are maintained in accordance with GAAP. The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have condensed certain prior year amounts on our condensed consolidated statements of cash flows to conform to current year presentations.

Condensed Consolidated Financial Statements

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

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.

Changes in Liquidity

On January 4, 2007, the FERC issued an order permitting Pinnacle West to transfer its market-based rate tariff and wholesale power sales agreements to a newly-created Pinnacle West subsidiary, Pinnacle West Marketing & Trading. Pinnacle West completed the transfer on February 1, 2007, which resulted in Pinnacle West no longer being a public utility under the Federal Power Act. As a result, Pinnacle West is no longer subject to FERC jurisdiction in connection with its issuance of securities or its incurrence of long-term debt.

The following table shows principal payments due on Pinnacle West’s and APS’ total long-term debt and capitalized lease requirements (dollars in millions) as of March 31, 2007:

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Consolidated
Year	Pinnacle West		APS
2007	$	2	$	1
2008		193		1
2009		1		1
2010		224		224
2011		578		401
Thereafter		2,260		2,260

Total	$	3,258	$	2,888

Regulatory Matters

APS General Rate Case

On December 15, 2006, hearings concluded in APS’ general rate case before the ACC. APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues, designed to recover the following (dollars in millions):


	Annual
	Revenue			Percentage
	Increase			Increase
Increased fuel and purchased power	$	314.4			14.8	%
Capital structure update		98.3			4.6	%
Rate base update, including acquisition of
Sundance Plant		46.2			2.2	%
Pension funding		41.3			1.9	%
Other items		(65.6	)		(3.1	)%


Total increase	$	434.6			20.4	%

The request is based on (a) a rate base of $4.5 billion as of September 30, 2005; (b) a base rate for fuel and purchased power costs of $0.0325 per kWh based on estimated 2007 prices; and (c) a capital structure of 45% long-term debt and 55% common stock equity, with a weighted-average cost of capital of 8.73% (5.41% for long-term debt and 11.50% for common stock equity). If the ACC approves the requested base rate increase for fuel and purchased power costs, subsequent PSA rate adjustments and/or PSA surcharges would be reduced because more of such costs would be recovered in base rates. See “Power Supply Adjustor” below.

APS has also suggested three additional measures for the ACC’s consideration to improve APS’ financial metrics while benefiting APS’ customers in the long run:

•

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

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

	•		Placing generation and distribution construction work in progress (“CWIP”) in rate base (in discussing this measure, APS assumed the inclusion of its June 30, 2006 CWIP balance of $261 million in rate base, which would increase APS’ revenue requirement by about $33 million); and

	•		Approving an “attrition adjustment” to provide APS a reasonable opportunity to earn an authorized return on equity given overall cost increases and higher levels of construction needed to accommodate ongoing customer growth (APS suggested a minimum attrition adjustment that would increase the return on equity by 1.7% to 4.1%).

The following table summarizes key rate case positions of APS, the ACC staff and the Arizona Residential Utility Consumer Office (“RUCO”), which the Arizona legislature established to represent the interests of residential utility consumers before the ACC:


	APS (a)						ACC Staff (b)						RUCO (b)
	Annual						Annual						Annual
	Revenue			Percentage			Revenue			Percentage			Revenue			Percentage
	Increase			Increase			Increase			Increase			Increase			Increase
Annual revenue increase (decrease)
Increased fuel and purchased power	$	314.4			14.8	%	$	193.5			9.2	%	$	280.0			13.2	%
Non-fuel components		120.2			5.6	%		(1.0	)		(0.1	)%		(68.0	)		(3.2	)%

Total	$	434.6			20.4	%	$	192.5			9.1	%	$	212.0			10.0	%


Base fuel rate (¢kWh)		3.25	¢					2.80	¢					3.12	¢

Return on equity		11.5	%					10.25	%					9.25	%

Capital structure
Long-term debt		45	%					45	%					50	%
Common equity		55	%					55	%					50	%

Rate base	$4.5 billion						$4.5 billion						$4.5 billion

Test year ended		9/30/2005						9/30/2005						9/30/2005


(a)		APS rejoinder testimony (10/4/06).

(b)		Final position per post-hearing brief and/or final schedules (1/22/07). The ACC staff has also recommended that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.

Other intervenors in the rate case include Arizonans for Electric Choice and Competition (“AECC”), a business coalition that advocates on behalf of retail electric customers in Arizona; and

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Phelps Dodge Mining Company (“Phelps Dodge”). In jointly-filed testimony, AECC and Phelps Dodge recommended that the ACC reduce APS’ requested annual increase by at least $134 million.

ALJ Recommended Order

On April 27, 2007, an ACC ALJ issued a recommended order in connection with the rate case and APS’ application to recover through a PSA surcharge approximately $45 million of deferrals related to unplanned 2005 Palo Verde outages. See “Power Supply Adjustor – PSA Deferrals Related to Unplanned Palo Verde Outages” below.

The ALJ recommended an increase of approximately $286 million, or 13.5%, in APS’ annual base retail revenues, which includes a fuel-related increase of approximately $280 million and non-fuel related increases of approximately $6 million. The ALJ recommended that the rate increase take effect June 1, 2007, at which time the interim PSA adjustor approved on May 1, 2006 would terminate. See “Interim Rate Increase” below. The ALJ’s recommended rate increase is based on a return on equity of 10.75%; a 45%/55% long-term debt/common equity capital structure; a weighted-average cost of capital of 8.32%; an original cost rate base of $4.4 billion; and a base rate for fuel and purchased power costs of $0.0312 per kWh.

The ALJ recommended various modifications to the PSA, including the following: (a) the annual PSA adjustor would be established based on projected, rather than historical, fuel and purchased power costs; (b) the 90/10 sharing arrangement under which APS absorbs 10% of retail fuel and purchased power costs above the base rate and retains 10% of the benefit below the base rate would be modified to exclude certain costs, such as renewable energy resources and the fixed element of long-term purchase power agreements acquired through competitive procurement; (c) the cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 per kWh limit to changes in the adjustor rate in any one year would remain in effect; and (d) there would not be a preset annual limit on the amount of fuel and purchased power costs that could be recovered through base rates and the PSA. The ALJ recommended that the modified PSA take effect June 1, 2007 based on the difference between APS’ proposed 2007 projected fuel and purchased power costs of $0.0325 per kWh and the base fuel rate of $0.0312 per kWh.

The ALJ recommended that the ACC not adopt any of APS’ additional suggestions described above to improve APS’ financial metrics (accelerated depreciation, inclusion of construction work in process in rate base, and an attrition adjustment).

The ALJ recommended (a) the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the PSA deferrals related to unplanned 2005 Palo Verde outages and (b) the recovery by APS of the balance of the PSA deferrals (approximately $34 million) over a twelve-month period through a temporary PSA surcharge to be effective concurrently with the implementation of new rates. As of May 1, 2007, these deferrals totaled approximately $48 million, including accrued interest. The ALJ also recommended that the ACC require APS and the ACC staff to develop “nuclear performance standards” for the ACC to consider in a separate proceeding. See “PSA Deferrals Related to Palo Verde Unplanned Outages” below.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

APS and other parties to the rate case may file exceptions to the recommended order no later than May 15, 2007. APS is currently evaluating the recommended order and expects to file its exceptions to the ALJ’s recommendations by that date. After the exceptions have been filed by APS and the other parties, the ACC will then consider the ALJ’s recommended order and the exceptions. We cannot predict the timing or the outcome of this rate case or the resulting levels of regulated revenues.

Interim Rate Increase

On January 6, 2006, APS filed with the ACC an application requesting an emergency interim rate increase of $299 million, or approximately 14%, to be effective April 1, 2006. APS later reduced this request to $232 million, or approximately 11%, due to a decline in expected 2006 natural gas and wholesale power prices. The purpose of the emergency interim rate increase was solely to address APS’ under-collection of higher annual fuel and purchased power costs. On May 2, 2006, the ACC approved an order in this matter that, among other things:

	•		authorized an interim PSA adjustor, effective May 1, 2006, that resulted in an interim retail rate increase of approximately 8.3% designed to recover approximately $138 million of fuel and purchased power costs incurred in 2006 (this interim adjustor, combined with the $15 million PSA surcharge approved by the ACC (see “Surcharge for Certain 2005 PSA Deferrals” below), resulted in a rate increase of approximately 9.0% designed to recover approximately $149 million of fuel and purchased power costs during 2006);

	•		provided that amounts collected through the interim PSA adjustor “remain subject to a prudency review at the appropriate time” and that “all unplanned Palo Verde outage costs for 2006 should undergo a prudence audit by [the ACC] Staff” (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below);

	•		encouraged parties to APS’ general rate case to “propose modifications to the PSA that will address on a permanent basis, the issues with timing of recovery when deferrals are large and growing”;

	•		affirmed APS’ ability to defer fuel and purchased power costs above the prior annual cap of $776.2 million until the ACC decides the general rate case; and

	•		encouraged APS to diversify its resources “through large scale, sustained energy efficiency programs, [using] low cost renewable energy resources as a hedge against high fossil fuel costs.”

On December 8, 2006, the ACC approved APS’ request to continue the interim PSA adjustor until rates become effective as a result of the general rate case.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Power Supply Adjustor

PSA Provisions

The PSA approved by the ACC in April 2005 as part of APS’ 2003 rate case provides for adjustment of retail rates to reflect variations in retail fuel and purchased power costs. Such adjustments are to be implemented by use of PSA adjustor rates and PSA surcharges. On January 25, 2006, the ACC modified the PSA in certain respects. The PSA, as modified, is subject to specified parameters and procedures, including the following:

	•		APS records deferrals for recovery or refund to the extent actual retail fuel and purchased power costs vary from the base fuel amount (currently $0.020743 per kWh);

	•		the deferrals are subject to a 90/10 sharing arrangement in which APS must absorb 10% of the retail fuel and purchased power costs above the base fuel amount and may retain 10% of the benefit from the retail fuel and purchased power costs that are below the base fuel amount;

	•		amounts to be recovered or refunded through the PSA annual adjustor rate are limited to (a) a cumulative plus or minus $0.004 per kWh from the base fuel amount over the life of the PSA and (b) a maximum plus or minus $0.004 change in the adjustor rate in any one year;

	•		the recoverable amount of annual retail fuel and purchased power costs through current base rates and the PSA was originally capped at $776.2 million; however, the ACC has removed the cap pending the ACC’s final ruling on APS’ pending request in the general rate case to have the cap eliminated or substantially raised;

	•		the adjustment is made annually each February 1^st and goes into effect automatically unless suspended by the ACC;

	•		the PSA will remain in effect for a minimum five-year period, but the ACC may eliminate the PSA at any time, if appropriate, in the event APS files a rate case before the expiration of the five-year period (which APS did by filing the general rate case noted above) or if APS does not comply with the terms of the PSA; and

	•		APS is prohibited from requesting PSA surcharges until after the PSA annual adjustor rate has been set each year. The amount available for potential PSA surcharges will be limited to the amount of accumulated deferrals through the prior year-end, which are not expected to be recovered through the annual adjustor or any PSA surcharges previously approved by the ACC.

2007 PSA Annual Adjustor

The annual adjustor rate is set for twelve-month periods beginning February 1 of each year. The current PSA annual adjustor rate was set at $0.003987 per kWh effective February 1, 2007, down slightly from the maximum $0.004 annual adjustor rate effective February 1, 2006. The new adjustor rate (a) essentially maintains the approximate 5% retail rate increase that took effect February 1, 2006 as a result of the 2006 PSA Annual Adjustor and

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which expired on February 1, 2007 and (b) is designed to recover approximately $109 million of deferred fuel and purchased power costs over the twelve-month period that began February 1, 2007.

Surcharge for Certain 2005 PSA Deferrals

On April 12, 2006, the ACC approved APS’ request to recover $15 million of 2005 PSA deferrals over a twelve-month period beginning May 2, 2006, representing a temporary rate increase of approximately 0.7%. Approximately $45 million of 2005 PSA deferrals remain subject to a pending application (see “PSA Deferrals Related to Unplanned Palo Verde Outages” below).

PSA Deferrals Related to Unplanned Palo Verde Outages

On February 2, 2006, APS filed with the ACC an application to recover approximately $45 million (plus interest) over a twelve-month period, representing a temporary rate increase of approximately 1.9%, proposed to begin no later than the ACC’s completion of its inquiry regarding the unplanned 2005 Palo Verde outages. During the course of the pending general rate case, the ACC staff recommended that the ACC disallow approximately $16 million ($10 million after income taxes) of the $45 million request. The ACC staff’s report alleges that four of the eleven Palo Verde outages in 2005 were “avoidable,” three of which resulted in the recommended disallowance. The report also finds, among other things, that:

	•		Three of the outages were due to “faulty or defective vendor supplied equipment” and concludes that APS’ actions were not imprudent in connection with these outages. The report recommends, however, that the ACC evaluate “the degree to which APS has sought appropriate legal or other remedies” in connection with these outages and that APS “be given the opportunity to demonstrate the steps that it has taken in this regard.”

	•		“Additional investigation will be needed to determine the cause of and responsibility for” the Palo Verde Unit 1 outage resulting from vibration levels in one of the Unit’s shutdown cooling lines.

The report also recommends that the ACC establish minimum three-year capacity factor targets for Palo Verde based on a three-year average of Palo Verde performance as compared to a group of comparable nuclear plants, with the ACC to review the recovery of any incremental fuel and replacement power costs attributable to Palo Verde not meeting the minimum targets.

APS disagrees with, and has contested, the report’s recommendation that the ACC disallow a portion of the $45 million of PSA deferrals. At the request of the ACC staff, this matter is being addressed by the ACC as part of APS’ pending general rate case. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of these deferrals. See “ALJ Recommended Order” above. APS believes the expenses in question were prudently incurred and, therefore, are recoverable.

As noted under “Interim Rate Increase” above, the ACC has directed the ACC staff to conduct a “prudence audit” of unplanned 2006 Palo Verde outage costs. This prudence review has not yet been completed. PSA deferrals related to these 2006 outages are estimated to be about $79 million through December 31, 2006. APS believes these expenses were prudently incurred and, therefore, are recoverable.

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Proposed Modifications to PSA (Requested In General Rate Case)

In its pending general rate case, APS has requested the following modifications to the PSA:

	•		The cumulative plus or minus $0.004 per kWh limit from the base fuel amount over the life of the PSA would be eliminated, while the maximum plus or minus $0.004 per kWh limit to changes in the adjustor rate in any one year would remain in effect;

	•		The $776.2 million annual limit on the retail fuel and purchased power costs under APS’ current base rates and the PSA would be removed or increased (although APS may defer fuel and purchased power costs above $776.2 million per year pending the ACC’s final ruling on APS’ pending request to have the cap eliminated or substantially raised);

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

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

The ACC staff has recommended the following potential changes to the PSA:

	•		Establishing the PSA annual adjustor, beginning in 2007, based on projected fuel costs rather than historical fuel costs; and

	•		Removing all existing limitations on fuel cost recovery, including the 90/10 sharing arrangement.

The ALJ in the rate case has recommended various modifications to the PSA. See “ALJ Recommended Order” above.

PSA Balance

The following table shows the changes in the deferred fuel and purchase power regulatory asset for the three months ended March 31, 2007 and 2006 (dollars in millions):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended
	March 31,
	2007			2006
Beginning balance	$	160		$	173
Deferred fuel and purchased power costs-current period		25			13
Interest on deferred fuel		2			1
Amounts recovered through revenues		(69	)		(18	)

Ending balance	$	118		$	169

Federal

Price Mitigation Plan

In July 2002, the FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The FERC adopted a price cap of $250 per MWh for the period subsequent to October 31, 2002. On February 13, 2006, the FERC increased this price cap to $400 per MWh for prospective sales. Sales at prices above the cap must be justified and are subject to potential refund. We do not expect this price cap to have a material impact on our financial statements.

FERC Order

On August 11, 2004, Pinnacle West, APS, Pinnacle West Energy, and APS Energy Services (collectively, the “Pinnacle West Companies”) submitted to the FERC an update to their three-year market-based rate review pursuant to the FERC’s order implementing a new generation market power analysis. On December 20, 2004, the FERC issued an order approving the Pinnacle West Companies’ market-based rates for control areas other than those of APS, Public Service Company of New Mexico (“PNM”) and Tucson Electric Power Company (“TEP”). The FERC staff required the Pinnacle West Companies to submit additional data with respect to these control areas, and the Pinnacle West Companies did so.

On April 17, 2006, the FERC issued an order revoking the Pinnacle West Companies’ market-based rate authority in the APS control area (the “April 17 Order”). The FERC found that the Pinnacle West Companies failed to provide the necessary information about the calculation of transmission imports into the APS control area to allow the FERC to make a determination regarding FERC’s generation market power “screens” in the APS control area. The FERC found that the Pinnacle West Companies may charge market-based rates in the PNM and TEP control areas.

As a result of the April 17 Order, the Pinnacle West Companies must charge cost-based rates, rather than market-based rates, in the APS control area for sales occurring after the date of the order, April 17, 2006. The Pinnacle West Companies are required to refund any amounts collected that exceed the default cost-based rates for all market rate sales within the APS control area from February 27, 2005 to April 17, 2006.

The Pinnacle West Companies filed a Request for Rehearing and Clarification of the April 17 Order on May 17, 2006 and submitted a supplemental compliance filing on July 28, 2006. On December 21, 2006, FERC issued an order granting clarification and provided additional details on

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

what steps the Pinnacle West Companies could take to correct the transmission import study previously submitted. The Pinnacle West Companies complied with this order and filed additional transmission studies and generation market power analyses on February 20, 2007.

Based upon an analysis of the April 17 Order and preliminary calculations of the refund obligations, at this time, neither Pinnacle West nor APS believes that the April 17 Order will have a material adverse effect on its financial position, results of operations or cash flows.

Retirement Plans and Other Benefits

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

The following table provides details of the plans’ benefit costs for the three months ended March 31, 2007 and 2006. Also included is the portion of these costs charged to expense, including administrative costs and excluding amounts billed to electric plant participants or capitalized as overhead construction (dollars in millions):


	Pension Benefits						Other Benefits
	Three Months Ended						Three Months Ended
	March 31,						March 31,
	2007			2006			2007			2006
Service cost-benefits earned during the period	$	14		$	15		$	6		$	7
Interest cost on benefit obligation		27			29			10			13
Expected return on plan assets		(29	)		(30	)		(12	)		(13	)
Amortization of:
Transition obligation		—			—			1			1
Prior service cost		1			1			—			—
Net actuarial loss		4			7			2			3

Net periodic benefit cost	$	17		$	22		$	7		$	11

Portion of cost charged to expense	$	8		$	9		$	3		$	5

APS’ share of costs charged to expense	$	7		$	8		$	3		$	4

Contributions

The contribution to our pension plan in 2007 is estimated to be approximately $22 million, and the contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $21 million. APS’ share is approximately 97% of both plans.

Business Segments

Pinnacle West’s two principal business segments are:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

Financial data for the three months ended March 31, 2007 and 2006 and at March 31, 2007 and December 31, 2006 by business segment is provided as follows (dollars in millions):


	Three Months Ended
	March 31,
	2007		2006
Operating Revenues:
Regulated electricity	$	536	$	466
Real estate		77		108
Other		82		96

Total	$	695	$	670


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

Total	$	17	$	13


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

Total	$	11,009	$	11,456

Income Taxes

As a result of a change in IRS guidance, we claimed a tax deduction related to an APS tax accounting method change on the 2001 federal consolidated income tax return. The accelerated deduction resulted in a $200 million reduction in the current income tax liability and a corresponding increase in the plant-related deferred tax liability. The 2001 federal consolidated income tax return is currently under examination by the IRS. As part of this ongoing examination, the IRS is reviewing this accounting method change and the resultant deduction. During 2007, it is expected that the IRS will finalize its examination and will issue a settlement on the tax accounting method change. At this time an estimate of the range of reasonably possible change in the uncertain tax position cannot be made. However, we do not expect the ultimate outcome of this examination to have a material

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

adverse impact on our financial position or results of operations. We expect that it will have a negative impact on cash flows.

We adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” on January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial. In addition, the guidance required us to reclassify certain tax benefits, which had the effect of increasing accrued taxes and deferred debits by approximately $50 million to better reflect the expected timing of the payment of taxes and interest.

The total amount of unrecognized tax benefits recorded in accrued taxes as of January 1, 2007 was $186 million, of which $179 million related to APS. The majority of the unrecognized tax benefits relate to the 2001 tax return position described above. Included in the balance of unrecognized tax benefits at January 1, 2007 are approximately $5 million of tax positions for consolidated Pinnacle West that, if recognized, would decrease our effective tax rate. For APS, approximately $3 million would have the same effect.

We continue to recognize potential accrued interest related to unrecognized tax benefits in the financial statements as income tax expense. As of January 1, 2007, the total amount of accrued interest expense related to uncertain tax positions was $54 million for consolidated Pinnacle West, which is included as a component of the $186 million unrecognized tax benefit noted above. APS’ share included in the total was approximately $53 million. Additionally, Pinnacle West has accrued $9 million of interest income to be received on the overpayment of income taxes for certain adjustments that we have filed, or will file, with the IRS. The application of FIN 48 did not have a material impact for the quarter ended March 31, 2007.

As of January 1, 2007, the tax year ending December 31, 1999 and all subsequent tax years remain subject to examination by federal and state taxing authorities. In addition, tax years ending prior to December 31, 1999 may remain subject to examination by state taxing authorities.

Variable-Interest Entities

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

APS is exposed to losses under the Palo Verde sale leaseback agreements upon the occurrence of certain events that APS does not consider to be reasonably likely to occur. Under certain circumstances (for example, the NRC issuing specified violation orders with respect to Palo Verde or the occurrence of specified nuclear events), APS would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of March 31, 2007, APS would have been required to assume approximately $214 million of debt and pay the equity participants approximately $177 million.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

10.

Derivative and Energy Trading Accounting

We use derivative instruments (primarily forward purchases and sales, swaps, options and futures) to manage our exposure to the commodity price risk inherent in the purchase and sale of fuel, electricity and emission allowances and credits. As of March 31, 2007, we hedged exposures to the price variability of the power and gas commodities for a maximum of 4.8 years. The changes in market value of such contracts have a high correlation to price changes in the hedged transactions. In addition, subject to specified risk parameters monitored by the ERMC, we engage in marketing and trading activities intended to profit from market price movements.

Cash Flow Hedges

The changes in the fair value of our hedged positions included in the Condensed Consolidated Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2007 and 2006 are comprised of the following (dollars in thousands):


	Three Months Ended
	March 31,
	2007		2006
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	911	$	(178	)
Losses from the change in options’ time value excluded from measurement of effectiveness		—		(18	)
Gains from the discontinuance of cash flow hedges		314		434

During the next twelve months ending March 31, 2008, we estimate that a net gain of $76 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

Our assets and liabilities from risk management and trading activities are presented in two categories.

The following tables summarize our assets and liabilities from risk management and trading activities at March 31, 2007 and December 31, 2006 (dollars in thousands):

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
March 31, 2007	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	82,204	$	84,955	$	(42,134	)	$	(78,680	)	$	46,345
Margin account and options		18,524		—		(1,671	)		—			16,853
Marketing and trading:
Mark-to-market		144,622		62,095		(92,192	)		(29,368	)		85,157
Options, emission allowances and other – at cost		108		5,221		(12,830	)		—			(7,501	)

Total	$	245,458	$	152,271	$	(148,827	)	$	(108,048	)	$	140,854


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2006	Assets		Assets		Liabilities			Other			(Liability)
Regulated electricity:
Mark-to-market	$	458,034	$	96,892	$	(481,661	)	$	(135,056	)	$	(61,791	)
Margin account and options		77,705		—		(2,228	)		—			75,477
Marketing and trading:
Mark-to-market		105,301		69,480		(61,553	)		(36,114	)		77,114
Options and emission allowances – at cost		—		839		(12,753	)		—			(11,914	)

Total	$	641,040	$	167,211	$	(558,195	)	$	(171,170	)	$	78,886

During the first quarter of 2007, we changed the presentation of mark-to-market positions related to natural gas basis swaps in the regulated electricity segment. We historically presented the buy side and the sell side of such swaps at fair value gross on our consolidated balance sheets, which resulted in mark-to-market assets and separate mark-to-market liabilities. We now offset these matching assets and liabilities, thus presenting the net mark-to-market position by contract, which correctly reflects the true nature of these contracts. The net asset/liability position as historically disclosed in the table above is unchanged. Further, this change has no impact on income, common stock equity or cash flows. Had we previously presented such amounts net, the effect on the December 31, 2006 balance sheet would have been to decrease Current Assets and Current Liabilities by $376 million and decrease Investments and Other Assets and Deferred Credits and Other by $59 million. We believe that the effect of presenting these contracts gross in prior periods is immaterial to previously issued financial statements.

We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $19 million at March 31, 2007 and an asset of $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

Cash or other assets may be required to serve as collateral against our open positions on certain energy-related contracts. Collateral provided to counterparties was $5 million at March 31, 2007 and $10 million at December 31, 2006, and is included in other current assets on the Condensed Consolidated Balance Sheets. Collateral provided to us by counterparties was $60 million at March 31, 2007 and $54 million at December 31, 2006, and is included in other current liabilities on the Condensed Consolidated Balance Sheets.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Credit Risk

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 11% of Pinnacle West’s $398 million of risk management and trading assets as of March 31, 2007. Our risk management process assesses and monitors the financial exposure of this and all other counterparties. Despite the fact that the great majority of trading counterparties’ securities are rated as investment grade by the credit rating agencies, including the counterparty discussed above, there is still a possibility that one or more of these companies could default, resulting in a material impact on consolidated earnings for a given period. Counterparties in the portfolio consist principally of financial institutions, major energy companies, municipalities and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. To manage credit risk, we employ collateral requirements, standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty and credit default swaps. Valuation adjustments are established representing our estimated credit losses on our overall exposure to counterparties.

11. Comprehensive Income (Loss)

Components of comprehensive income (loss) for the three months ended March 31, 2007 and 2006 are as follows (dollars in thousands):


	Three Months Ended
	March 31,
	2007			2006
Net income	$	16,530		$	12,455

Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		62,560			(204,983	)
Net reclassification of realized gains to income (b)		(5,013	)		(17,530	)
Reclassification of pension and other postretirement benefits to income		251			—
Income tax benefit (expense) related to items of other comprehensive income (loss)		(22,570	)		86,891

Total other comprehensive income (loss)		35,228			(135,622	)

Comprehensive income (loss)	$	51,758		$	(123,167	)


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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


(b)		These amounts primarily include the reclassification of unrealized gains and losses to realized for contracted commodities delivered during the period.

12. Commitments and Contingencies

Palo Verde Nuclear Generating Station

Spent Nuclear Fuel and Waste Disposal

Nuclear power plant operators are required to enter into spent fuel disposal contracts with the DOE, and the DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Policy Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before at least 2017. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and the DOE’s delay, a number of utilities, including APS (on behalf of itself and the other Palo Verde owners), filed damages actions against the DOE in the Court of Federal Claims. APS is currently pursuing that damages claim.

APS currently estimates it will incur $147 million (in 2006 dollars) over the life of Palo Verde for its share of the costs related to the on-site interim storage of spent nuclear fuel. At March 31, 2007, APS had a regulatory liability of $2.8 million that represents amounts recovered in retail rates in excess of amounts spent for on-site interim spent fuel storage.

NRC Inspection

In October 2006, the NRC conducted an inspection of the Palo Verde emergency diesel generators after a Palo Verde Unit 3 generator started but did not provide electrical output during routine inspections on July 25 and September 22, 2006.

On February 22, 2007, the NRC issued a “white” finding (low to moderate safety significance) for this matter. In connection with its finding, the NRC stated that it would “use the NRC Action Matrix to determine the most appropriate response and any increase in NRC oversight, or actions [APS needs] to take in response to the most recent performance deficiencies” and notify APS of its determination at a later date. Under the NRC’s Action Matrix, this finding, coupled with a previous NRC “yellow” finding relating to a 2004 matter involving Palo Verde’s safety injection systems, resulted in Palo Verde Unit 3 being placed in the “multiple/repetitive degraded cornerstone” column of the NRC’s Action Matrix, which will result in an enhanced NRC inspection regimen. APS continues to implement its plan to improve Palo Verde’s operational performance.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

California Energy Market Issues and Refunds in the Pacific Northwest

FERC

In July 2001, the FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. APS was a seller and a purchaser in the California markets at issue and, to the extent that refunds are ordered, APS should be a recipient as well as a payor of such amounts. The FERC is still considering the evidence and refund amounts have not yet been finalized. However, on September 6, 2005, the Ninth Circuit issued a decision, concluding that the FERC may not order refunds from entities that are not within the FERC’s jurisdiction. Because a number of the entities owing refunds under the FERC’s calculations are not within the FERC’s jurisdiction, this order may affect the level of recovery of refunds due in this proceeding. In addition, on August 8, 2005, the FERC issued an order allowing sellers in the California markets to demonstrate that its refund methodology results in an overall revenue shortfall for their transactions in the relevant markets over a specified time frame. More than twenty sellers made such cost recovery filings on September 14, 2005. On January 26, 2006, the FERC conditionally accepted thirteen of these filings, reducing the refund liability for these sellers. Correspondingly, this will reduce the recovery of total refunds in the California markets. On August 2, 2006, the Ninth Circuit issued a decision on the appropriate temporal scope and the type of transactions that are properly subject to the refund orders. In the decision, the Court preserved the scope of the FERC’s existing refund proceedings, but also expanded it potentially to include additional transactions, remanding the orders to the FERC for further proceedings. Various parties filed petitions for rehearing on this order. In addition, on December 19, 2006, the Ninth Circuit issued a decision on the appropriate standard of review at the FERC on wholesale power contracts in the refund proceedings, specifically addressing the application of the so-called “just and reasonable” standard as opposed to the “public interest” standard. In so doing, the Ninth Circuit remanded the matter back to the FERC with the requirement that the FERC review the refund matter using the appropriate standard of review. Like the August 2, 2006 Ninth Circuit decision, the December 19, 2006 decision has the potential to expand the existing FERC refund proceedings. We currently believe the refund claims at FERC will have no material adverse impact on our financial position, results of operations, cash flow or liquidity.

On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including the Company, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present under market-based rates. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint was dismissed by the FERC and the State of California appealed the matter to the Ninth Circuit Court of Appeals. In an order issued September 9, 2004, the Ninth Circuit upheld the FERC’s authority to permit market-based rates, but rejected the FERC’s claim that it was without authority to consider retroactive refunds when a utility has not strictly adhered to the quarterly reporting requirements of the market-based rate system. On September 9, 2004, the Ninth Circuit remanded the case to the FERC for further proceedings. Several of the intervenors in this appeal filed a petition for rehearing of this decision on October 25, 2004. The petition for rehearing was denied on July 31, 2006. On October 10, 2006, the State of California filed a motion to stay the issuance of the mandate (scheduled to be issued on November 2, 2006) until June 13, 2007. The request for stay was granted. The outcome of the further proceedings cannot be predicted at this time.

The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for wholesale sales in the Pacific Northwest. The FERC affirmed the ALJ’s conclusion that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. This decision has now been appealed to the Ninth Circuit Court of Appeals and oral argument was held on January 8, 2007. Although the FERC ruling in this matter is being appealed

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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

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

FERC Order

See “FERC Order” in Note 5 for a discussion of an order issued by the FERC on April 17, 2006.

Natural Gas Supply

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

On July 9, 2003, the FERC issued an order that altered the capacity rights of parties to the 1996 settlement but maintained the cost responsibility provisions agreed to by parties to that settlement. On December 28, 2004, the D.C. Court of Appeals upheld the FERC’s authority to alter the capacity rights of parties to the settlement. With respect to the FERC’s authority to maintain the cost responsibility provisions of the settlement, a party has sought appellate review and is seeking to reallocate the cost responsibility associated with the changed contractual obligations in a way that would be less favorable to APS than under the FERC’s July 9, 2003 order. Should this party prevail on this point, APS’ annual capacity cost could be increased by approximately $3 million per year after income taxes for the period September 2003 through December 2005. This appeal had been stayed pending further consideration by the FERC. On May 26, 2006, the FERC issued an Order on Remand affirming its earlier decision that there is no basis for modifying the settlement rates during the remaining term of the settlement. The party seeking appellate review is continuing to pursue an appeal of this issue and has therefore sought rehearing of the May 26, 2006 order. The FERC’s next status report is due to the DC Circuit Court of Appeals by August 7, 2007.

Navajo Nation Litigation

In June 1999, the Navajo Nation served Salt River Project with a lawsuit filed in the United States District Court for the District of Columbia (the “D.C. Lawsuit”) naming Salt River Project, several Peabody Coal Company entities (collectively, “Peabody”), Southern California Edison Company and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo Generating

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Station and the Mohave Generating Station. APS is a 14% owner of the Navajo Generating Station, which Salt River Project operates. The D.C. Lawsuit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants “from all possessory interests and Navajo Tribal lands arising out of the [primary coal lease].” In July 2001, the court dismissed all claims against Salt River Project.

In January 2005, Peabody served APS with a lawsuit filed in the Circuit Court for the City of St. Louis naming APS and the other Navajo Generating Station participants and seeking, among other things, a declaration that the participants “are obligated to reimburse Peabody for any royalty, tax, or other obligation arising out of the D.C. Lawsuit.” Based on APS’ ownership interest in the Navajo Generating Station, APS could be liable for up to 14% of any such obligation. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter.

Superfund

Superfund establishes liability for the cleanup of hazardous substances found contaminating the soil, water or air. Those who generated, transported or disposed of hazardous substances at a contaminated site are among those who are PRPs. PRPs may be strictly, and often jointly and severally, liable for clean-up. On September 3, 2003, the EPA advised APS that the EPA considers APS to be a PRP in the Motorola 52^nd Street Superfund Site, Operable Unit 3 (OU3) in Phoenix, Arizona. APS has facilities that are within this Superfund site. APS and Pinnacle West have agreed with the EPA to perform certain investigative activities of the APS facilities within OU3. Because the investigation has not yet been completed and ultimate remediation requirements are not yet finalized, neither APS nor Pinnacle West can currently estimate the expenditures which may be required.

Litigation

We are party to various other claims, legal actions and complaints arising in the ordinary course of business, including but not limited to environmental matters related to the Clean Air Act, Navajo Nation issues and EPA and ADEQ issues. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our results of operations, cash flows or liquidity.

13. Nuclear Insurance

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the program exceed the accumulated funds, APS could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $101 million, subject to an annual limit of $15 million per incident, to be periodically adjusted for inflation. Based on APS’ interest in the three Palo Verde units, APS’ maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $13 million.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen accidental outage of any of the three units. The property damage, decontamination, and replacement power coverages are provided by Nuclear Electric Insurance Limited (NEIL). APS is subject to retrospective assessments under all NEIL policies if NEIL’s losses in any policy year exceed accumulated funds. The maximum amount of retrospective assessments APS could incur under the current NEIL policies totals $18.1 million. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

14. Other Income and Other Expense

The following table provides detail of other income and other expense for the three months ended March 31, 2007 and 2006 (dollars in thousands):


	Three Months Ended
	March 31,
	2007			2006
Other income:
Interest income	$	3,413		$	4,905
SunCor other income (a)		579			166
Miscellaneous		520			396

Total other income	$	4,512		$	5,467


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

Total other expense	$	(6,353	)	$	(4,541	)


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

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

15. Guarantees

We have issued parental guarantees and letters of credit and obtained surety bonds on behalf of our subsidiaries. Our parental guarantees for Pinnacle West Marketing & Trading relate to commodity energy products. Our credit support instruments enable APS Energy Services to offer commodity energy and energy-related products. Non-performance or non-payment under the original contract by our subsidiaries would require us to perform under the guarantee or surety bond. No liability is currently recorded on the Condensed Consolidated Balance Sheets related to Pinnacle

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

West’s current outstanding guarantees on behalf of its subsidiaries. Our guarantees have no recourse or collateral provisions to allow us to recover amounts paid under the guarantees. The amounts and approximate terms of our guarantees and surety bonds for each subsidiary at March 31, 2007 are as follows (dollars in millions):


	Guarantees				Surety Bonds
			Term				Term
	Amount		(in years)		Amount		(in years)
Parental:
Pinnacle West Marketing & Trading	$	63		1	$	—		—
APS Energy Services		15		1		19		1

Total	$	78			$	19

At March 31, 2007, Pinnacle West had approximately $5 million of letters of credit related to workers’ compensation expiring in late 2007. We intend to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

APS has entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 2007, approximately $200 million of letters of credit were outstanding to support existing pollution control bonds of approximately $200 million. The letters of credit are available to fund the payment of principal and interest of such debt obligations and expire in 2010. APS has also entered into approximately $86 million of letters of credit to support certain equity lessors in the Palo Verde sale leaseback transactions (see Note 9 for further details on the Palo Verde sale leaseback transactions). These letters of credit expire in 2010. Additionally, at March 31, 2007, APS had approximately $4 million of letters of credit related to counterparty collateral requirements expiring in 2007. APS intends to provide from either existing or new facilities for the extension, renewal or substitution of the letters of credit to the extent required.

We enter into agreements that include indemnification provisions relating to liabilities arising from or related to certain of our agreements; most significantly, APS has agreed to indemnify the equity participants and other parties in the Palo Verde sale leaseback transactions with respect to certain tax matters. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnification provisions cannot be reasonably estimated. Based on historical experience and evaluation of the specific indemnities, we do not believe that any material loss related to such indemnification provisions is likely.

16. Earnings Per Share

The following table presents earnings per weighted average common share outstanding for the three months ended March 31, 2007 and 2006:

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS


	Three Months Ended
	March 31,
	2007		2006
Basic earnings per share:
Income from continuing operations	$	0.16	$	0.12
Income from discontinued operations		0.01		0.01

Earnings per share – basic	$	0.17	$	0.13


Diluted earnings per share:
Income from continuing operations	$	0.16	$	0.12
Income from discontinued operations		—		0.01

Earnings per share – diluted	$	0.16	$	0.13

Dilutive stock options and performance shares increased average common shares outstanding by approximately 577,000 shares and 334,000 shares for the three months ended March 31, 2007 and March 31, 2006, respectively.

For the three-month period ended March 31, 2007, there were no outstanding options to purchase shares excluded from the computation of earnings per share because the options’ exercise prices were less than the average market price of the common shares. Options to purchase shares of common stock that were excluded from the computation of diluted earnings per share were 747,874 shares for the three-month period ended March 31, 2006.

17. Discontinued Operations

SunCor(real estate segment)–In 2006 and 2007, SunCor sold commercial properties, which are required to be reported as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income in accordance with SFAS No. 144. The following table contains SunCor’s revenue, income before income taxes and income after income taxes classified as discontinued operations on Pinnacle West’s Condensed Consolidated Statements of Income for the three months ended March 31, 2007 and 2006 (dollars in millions):


	Three Months Ended
	March 31,
	2007		2006
Revenue	$	2	$	1
Income before income taxes		1		1
Income after income taxes		1		1

18. Nuclear Decommissioning Trust

To fund the costs APS expects to incur to decommission Palo Verde, APS established external decommissioning trusts in accordance with NRC regulations. APS invests the trust funds in fixed income and equity securities. APS applies the provisions of SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” in accounting for investments in decommissioning trust funds, and classifies these investments as available for sale. As a result, we

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

record the decommissioning trust funds at their fair value on our Condensed Consolidated Balance Sheets. Because of the ability of APS to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, APS has recorded the offsetting amount of unrealized gains (losses) on investment securities in other regulatory liabilities/assets. The following table summarizes the fair value of APS’ nuclear decommissioning trust fund assets at March 31, 2007 and December 31, 2006 (dollars in millions):


			Total Unrealized
	Fair Value		Gains
March 31, 2007
Equity securities	$	167	$	63
Fixed income securities		182		3

Total	$	349	$	66


December 31, 2006
Equity securities	$	164	$	63
Fixed income securities		180		3

Total	$	344	$	66

The costs of securities sold are determined on the basis of specific identification. The following table sets forth approximate gains and losses and proceeds from the sale of securities by the nuclear decommissioning trust funds (dollars in millions):


	Three Months Ended
	March 31,
	2007			2006
Realized gains	$	1		$	1
Realized losses		(1	)		(1	)
Proceeds from the sale of securities		63			34

The fair value of fixed income securities, summarized by contractual maturities, at March 31, 2007 is as follows (dollars in millions):


Fair Value	March 31, 2007
Less than one year	$	15
1 year - 5 years		41
5 years - 10 years		41
Greater than 10 years		85

Total	$	182

19. New Accounting Standards

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This guidance establishes a framework for measuring fair value and expands disclosures about fair value measurements. The Statement is effective for us on January 1, 2008. We are currently evaluating this new guidance.

PINNACLE WEST CAPITAL CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities.” SFAS No. 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 is effective for us on January 1, 2008. We are currently evaluating this new guidance.

See Note 8 for a discussion of FASB Interpretation No. 48 on accounting for uncertainty in income taxes, which we adopted January 1, 2007. The effect of applying the new guidance was not significantly different in terms of tax impacts from the application of our previous policy. Accordingly, the impact to retained earnings upon adoption was immaterial.

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


	Three Months Ended
	March 31,
	2007			2006
ELECTRIC OPERATING REVENUES
Regulated electricity	$	537,376		$	467,222
Marketing and trading		884			9,647

Total		538,260			476,869


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

Total		497,671			451,825

OPERATING INCOME		40,589			25,044


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

Total		4,727			5,163


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

Total		40,999			35,728


NET INCOME (LOSS)	$	4,317		$	(5,521	)

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

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED BALANCE SHEETS
(unaudited)
(dollars in thousands)


	March 31,			December 31,
	2007			2006
ASSETS

UTILITY PLANT
Electric plant in service and held for future use	$	11,195,376		$	11,094,868
Less accumulated depreciation and amortization		3,843,518			3,789,534

Net		7,351,858			7,305,334

Construction work in progress		419,639			365,704
Intangible assets, net of accumulated amortization		89,775			95,601
Nuclear fuel, net of accumulated amortization		69,539			60,100

Total utility plant		7,930,811			7,826,739


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

Total investments and other assets		502,814			508,426


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

Total current assets		695,595			1,240,453


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

Total deferred debits		900,463			938,074


TOTAL ASSETS	$	10,029,683		$	10,513,692

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

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


	March 31,		December 31,
	2007		2006
LIABILITIES AND EQUITY

CAPITALIZATION
Common stock	$	178,162	$	178,162
Additional paid-in capital		2,065,918		2,065,918
Retained earnings		924,434		960,405
Accumulated other comprehensive income:
Derivative instruments		34,150		2,988

Common stock equity		3,202,664		3,207,473
Long-term debt less current maturities		2,877,377		2,877,502

Total capitalization		6,080,041		6,084,975


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

Total current liabilities		833,231		1,278,566


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

Total deferred credits and other		3,116,411		3,150,151


COMMITMENTS AND CONTINGENCIES (NOTES 5, 8, 12, 13 and 15)

TOTAL LIABILITIES AND EQUITY	$	10,029,683	$	10,513,692

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

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


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

Net cash flow provided by operating activities		185,452			9,091


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

Net cash flow used for investing activities		(164,471	)		(149,058	)


CASH FLOWS FROM FINANCING ACTIVITIES
Equity infusion		—			210,000
Dividends paid on common stock		—			(42,500	)
Repayment and reacquisition of long-term debt		(287	)		(821	)

Net cash flow provided by (used for) financing activities		(287	)		166,679


NET INCREASE IN CASH AND CASH EQUIVALENTS		20,694			26,712

CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		81,870			49,933


CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	102,564		$	76,645

Supplemental disclosure of cash flow information:
Cash paid during the year for:
Income taxes, net of refunds	$	44,088		$	—
Interest, net of amounts capitalized	$	45,793		$	24,297

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

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


	Condensed	APS’
	Consolidated	Supplemental
	Footnote	Footnote
	Reference	Reference
Consolidation and Nature of Operations	Note 1	—
Condensed Consolidated Financial Statements	Note 2	—
Quarterly Fluctuations	Note 3	—
Changes in Liquidity	Note 4	—
Regulatory Matters	Note 5	—
Retirement Plans and Other Benefits	Note 6	—
Business Segments	Note 7	—
Income Taxes	Note 8	—
Variable Interest Entities	Note 9	—
Derivative and Energy Trading Accounting	Note 10	Note S-1
Comprehensive Income (Loss)	Note 11	Note S-2
Commitments and Contingencies	Note 12	—
Nuclear Insurance	Note 13	—
Other Income and Other Expense	Note 14	Note S-3
Guarantees	Note 15	—
Earnings Per Share	Note 16	—
Discontinued Operations	Note 17	—
Nuclear Decommissioning Trust	Note 18	—
New Accounting Standards	Note 19	—

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-1. Derivative and Energy Trading Accounting

APS is exposed to the impact of market fluctuations in the commodity price of electricity, natural gas and emissions allowances. As part of its overall risk management program, APS uses various commodity instruments that qualify as derivatives to hedge purchases and sales of electricity, fuels, and emission allowances and credits. As of March 31, 2007, APS hedged exposures to these risks for a maximum of 4.8 years.

Cash Flow Hedges

The changes in the fair value of APS’ hedged positions included in the APS Condensed Statements of Income, after consideration of amounts deferred under the PSA, for the three months ended March 31, 2007 and 2006 were comprised of the following (dollars in thousands):


	Three Months Ended
	March 31,
	2007		2006
Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting	$	911	$	(436	)
Losses from the change in options’ time value excluded from measurement of effectiveness		—		(18	)
Gains from the discontinuance of cash flow hedges		150		159

During the next twelve months ending March 31, 2008, APS estimates that a net gain of $39 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect of market price changes for the related hedged transactions. To the extent the amounts are eligible for inclusion in the PSA, the amounts will be recorded as either a regulatory asset or liability and have no effect on earnings (see Note 5).

APS’ assets and liabilities from risk management and trading activities are presented in two categories.

The following tables summarize APS’ assets and liabilities from risk management and trading activities at March 31, 2007 and December 31, 2006 (dollars in thousands):

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
March 31, 2007	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	82,204	$	84,955	$	(42,134	)	$	(78,680	)	$	46,345
Margin account and options		18,524		—		(1,671	)		—			16,853
Marketing and Trading:
Mark-to-market		4,550		—		(7,845	)		—			(3,295	)
Options at cost		—		—		(312	)		—			(312	)

Total	$	105,278	$	84,955	$	(51,962	)	$	(78,680	)	$	59,591


			Investments					Deferred
	Current		and Other		Current			Credits and			Net Asset
December 31, 2006	Assets		Assets		Liabilities			Other			(Liability)
Regulated Electricity:
Mark-to-market	$	458,034	$	96,892	$	(481,661	)	$	(135,056	)	$	(61,791	)
Margin account and options		77,705		—		(2,228	)		—			75,477
Marketing and Trading:
Mark-to-market		3,569		—		(6,654	)		—			(3,085	)
Options at cost		—		—		(312	)		—			(312	)

Total	$	539,308	$	96,892	$	(490,855	)	$	(135,056	)	$	10,289

We maintain a margin account with a broker to support our risk management and trading activities. The margin account was an asset of $19 million at March 31, 2007 and $73 million at December 31, 2006 and is included in the margin account in the table above. Cash is deposited with the broker in this account at the time futures or options contracts are initiated. The change in market value of these contracts (reflected in mark-to-market) requires adjustment of the margin account balance.

Cash or other assets may be required to serve as collateral against APS’ open positions on certain energy-related contracts. No collateral was provided to counterparties at March 31, 2007 and $2 million was provided at December 31, 2006 and is included in other current assets on the Condensed Balance Sheets. Collateral provided to us by counterparties was $1 million at both March 31, 2007 and December 31, 2006, and is included in other current liabilities on the Condensed Balance Sheets.

ARIZONA PUBLIC SERVICE COMPANY
SUPPLEMENTAL NOTES TO THE CONDENSED FINANCIAL STATEMENTS

S-2. Comprehensive Income (Loss)

Components of APS’ comprehensive income (loss) for the three months ended March 31, 2007 and 2006 are as follows (dollars in thousands):


	Three Months Ended
	March 31,
	2007			2006
Net income (loss)	$	4,317		$	(5,521	)

Other comprehensive income (loss):
Net unrealized gains (losses) on derivative instruments (a)		50,545			(162,892	)
Net reclassification of realized losses (gains) to income (b)		741			(10,116	)
Net income tax benefit (expense) related to items of other comprehensive income (loss)		(20,124	)		67,560

Total other comprehensive income (loss)		31,162			(105,448	)

Comprehensive income (loss)	$	35,479		$	(110,969	)


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

(b)		These amounts primarily include the reclassification of unrealized gains and losses to realized gains and losses for contracted commodities delivered during the period.

S-3. Other Income and Other Expense

The following table provides detail of APS’ other income and other expense for the three months ended March 31, 2007 and 2006 (dollars in thousands):


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

Total other income	$	4,433		$	4,806


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

Total other expense	$	(4,904	)	$	(3,680	)


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

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion should be read in conjunction with Pinnacle West’s Condensed Consolidated Financial Statements and Arizona Public Service Company’s Condensed Financial Statements and the related Notes that appear in Item 1 of this report.

OVERVIEW

Pinnacle West owns all of the outstanding common stock of APS. APS is a vertically-integrated electric utility that provides retail and wholesale electric service to most of the state of Arizona, with the major exceptions of about one-half of the Phoenix metropolitan area, the Tucson metropolitan area and Mohave County in northwestern Arizona. APS has historically accounted for a substantial part of our revenues and earnings, and is expected to continue to do so. Customer growth in APS’ service territory is about three times the national average and remains a fundamental driver of our revenues and earnings.

The ACC regulates APS’ retail electric rates. The key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC. As discussed in greater detail in Note 5, these proceedings consist of:

	•		a general retail rate case pursuant to which APS is requesting a 20.4%, or $434.6 million, increase in its annual retail electricity revenues;

	•		an application for a temporary rate increase of approximately 1.9%, through a PSA surcharge, to recover $45 million in retail fuel and purchased power costs relating to Palo Verde’s 2005 unplanned outages that were deferred by APS in 2005 under the PSA and are subject to the ACC’s completion of an inquiry regarding the outages (this matter is now being addressed in the general retail rate case); and

	•		the ACC’s prudency review of amounts collected through the May 2, 2006 interim PSA adjustor (see “Interim Rate Increase” in Note 5) related to unplanned 2006 Palo Verde outages.

SunCor, our real estate development subsidiary, has been and is expected to be an important source of earnings. See discussion below in “Pinnacle West Consolidated – Factors Affecting our Financial Outlook – Subsidiaries.” Our subsidiary, APS Energy Services, provides competitive commodity-related energy services and energy-related products and services to commercial and industrial retail customers in the western United States. El Dorado, our investment subsidiary, owns minority interests in several energy-related investments and Arizona community-based ventures. Pinnacle West Marketing & Trading is the Company’s newly-formed marketing and trading subsidiary. Activity in this subsidiary began in February 2007. See Note 4.

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

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

EARNINGS CONTRIBUTION BY BUSINESS SEGMENT

Pinnacle West’s two principal business segments are:

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

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

The following table summarizes income from continuing operations by segment for the three months ended March 31, 2007 and 2006 and reconciles net income in total (dollars in millions):


	Three Months Ended
	March 31,
	2007		2006
Regulated electricity	$	4	$	(12	)
Real estate		8		21
Other (a)		4		3

Income from continuing operations		16		12
Discontinued operations – net of tax:
Real estate		1		1

Net income	$	17	$	13


(a)		Primarily marketing and trading activity.

PINNACLE WEST CONSOLIDATED – RESULTS OF OPERATIONS

General

Throughout the following explanations of our results of operations, we refer to “gross margin.” With respect to our regulated electricity segment, gross margin refers to operating revenues less fuel and purchased power costs. “Gross margin” is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.1 reconciles this non-GAAP financial measure to operating income, which is the most directly comparable financial measure calculated and presented in accordance with accounting principles generally accepted in the United States (GAAP). We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses.

Deferred Fuel and Purchased Power Costs

Our subsidiary, APS, settled its 2003 general retail rate case effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund

fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications. See “Power Supply Adjustor” in Note 5.

Since the inception of the PSA, APS has incurred substantially higher fuel and purchased power costs than those authorized for recovery through APS’ current base rates, primarily due to the use of higher cost resources and higher fuel prices, and has deferred those cost differences in accordance with the PSA. The balance of APS’ PSA accumulated unrecovered deferrals at March 31, 2007 was approximately $118 million. The recovery of PSA deferrals through ACC approved adjustors and surcharges recorded as revenue is offset dollar-for-dollar by the amortization of those deferred expenses recorded as fuel and purchased power.

APS recorded PSA deferrals of (a) $45 million related to replacement power costs in 2005 associated with unplanned Palo Verde outages and (b) $79 million related to replacement power costs in 2006 associated with unplanned outages or reduced power operations at Palo Verde. The PSA deferrals associated with these unplanned Palo Verde outages and reduced power operations are the subject of ACC prudence reviews. The ACC staff has completed its prudence review of 2005 unplanned outages and has recommended disallowance of $16 million of the 2005 costs. The recommendation is being considered as part of APS’ general rate case currently pending before the ACC. See “PSA Deferrals Related to Unplanned Palo Verde Outages” in Note 5. The ALJ in the rate case has recommended the disallowance of approximately $14 million, including accrued interest ($8 million after income taxes), of the deferrals related to the unplanned 2005 Palo Verde outages. See “ALJ Recommended Order” in Note 5. Neither the ACC staff recommendation nor the ALJ recommendation changes management’s belief that the expenses in question were prudently incurred and, therefore, are recoverable. The prudence review of 2006 unplanned outages has not yet been completed.

Operating Results – Three-month period ended March 31, 2007 compared with three-month period ended March 31, 2006

Our consolidated net income for the three months ended March 31, 2007 was $17 million compared with $13 million for the comparable prior-year period. Net income increased $4 million in the period-to-period comparison, reflecting the following changes in earnings by segment:

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

	•		Real Estate Segment – Net income decreased approximately $13 million primarily due to lower sales of land parcels and residential property.

	•		Other miscellaneous items, net, increased approximately $1 million.

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


	Increase (Decrease)
	Pretax			After Tax
Regulated electricity segment gross margin:
Effects of cooler weather on retail sales	$	13		$	8
Higher retail sales due to customer growth, excluding weather effects		10			6
Higher fuel and purchased power costs due to increased prices (see “Deferred Fuel and Purchased Power Costs” above)		(14	)		(9	)
Increased deferred fuel and purchased power costs		12			7
Miscellaneous items, net		3			3

Net increase in regulated electricity segment gross margin		24			15
Lower real estate segment contribution primarily due to decreased sales of land parcels and residential property		(21	)		(13	)
Operations and maintenance decreases primarily due to:
Generation costs, including fewer power plant maintenance outages		4			2
Miscellaneous items, net		3			2
Other miscellaneous items, net		(4	)		(2	)

Net increase in net income	$	6		$	4

Regulated Electricity Segment Revenues

Regulated electricity segment revenues were $70 million higher for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

	•		a $51 million increase in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);

	•		an $18 million increase in retail revenues due to cooler weather;

	•		a $13 million increase in retail revenues related to customer growth, excluding weather effects;

	•		a $5 million decrease in Off-System Sales due to lower sales volumes; and

	•		a $7 million decrease due to miscellaneous factors.

Real Estate Segment Revenues

Real estate segment revenues were $31 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

•

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

	•		a $15 million decrease in revenue primarily due to a significant land parcel sale in 2006 without a comparable sale in 2007; and

	•		a $4 million increase due to miscellaneous factors.

Other Revenues

Marketing and trading revenues were $13 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

	•		an $11 million decrease from lower competitive retail sales volumes in California; and

	•		a $2 million decrease due to miscellaneous factors.

LIQUIDITY AND CAPITAL RESOURCES

Capital Needs and Resources – Pinnacle West Consolidated

Capital Expenditure Requirements

The following table summarizes the actual capital expenditures for the three months ended March 31, 2007 and estimated capital expenditures for the next three years (dollars in millions):

CAPITAL EXPENDITURES


	Three Months Ended		Estimated for the Year Ended
	March 31,		December 31,
	2007		2007		2008		2009
APS
Distribution	$	97	$	362	$	411	$	459
Transmission		40		173		200		288
Generation		45		388		298		335
Other (a)		1		26		39		40

Subtotal		183		949		948		1,122
SunCor (b)		39		131		101		100
Other		1		13		19		10

Total	$	223	$	1,093	$	1,068	$	1,232


(a)		Primarily information systems and facilities projects.

(b)		Consists primarily of capital expenditures for residential land development and retail and office building construction reflected in “Real estate investments” on the Condensed Consolidated Statements of Cash Flows.

Distribution and transmission capital expenditures are comprised of infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and

facility costs. Examples of the types of projects included in the forecast include lines, substations, line extensions to new residential and commercial developments and upgrades to customer information systems. Major transmission projects are driven by strong regional customer growth.

Generation capital expenditures are comprised of various improvements to APS’ existing fossil and nuclear plants and the replacement of Palo Verde steam generators (see below). Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers and environmental equipment. Environmental expenditures are estimated at approximately $80 million to $100 million per year for 2007, 2008 and 2009. Generation also includes nuclear fuel expenditures of approximately $110 million for 2007, $40 million for 2008 and $100 million for 2009.

The Palo Verde owners have approved the manufacture of one additional set of steam generators. These generators will be installed in Unit 3 and are scheduled for completion in the Fall of 2007 at an approximate cost of $70 million (APS’ share). Approximately $30 million of the Unit 3 steam generator costs have been incurred through March 31, 2007, with the remaining $40 million included in the capital expenditures table above. Capital expenditures will be funded with internally generated cash and/or external financings.

Contractual Obligations

Our future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.6 billion at December 31, 2006 to $2.8 billion at March 31, 2007 as follows (dollars in billions):


2007	2008-2009		2010-2011		Thereafter		Total
$0.5	$	0.5	$	0.5	$	1.3	$	2.8

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

Upon adoption of FIN 48, we are now required to include uncertain tax positions in our contractual obligation disclosure. We have uncertain tax positions of approximately $186 million and we expect to pay these in 2007. See Note 8.

Off-Balance Sheet Arrangements

Guarantees and Letters of Credit

We and certain of our subsidiaries have issued guarantees and letters of credit in support of our unregulated businesses. We have also obtained surety bonds on behalf of APS Energy Services. We have not recorded any liability on our Condensed Consolidated Balance Sheets with respect to these obligations. We generally agree to indemnification provisions related to liabilities arising from or related to certain of our agreements, with limited exceptions depending on the particular agreement. See Note 15 for additional information regarding guarantees and letters of credit.

Credit Ratings

The ratings of securities of Pinnacle West and APS as of May 8, 2007 are shown below. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of Pinnacle West’s or APS’ securities and serve to increase the cost of and access to capital. It may also require additional collateral related to certain derivative instruments (see Note 10).


	Moody’s	Standard & Poor’s	Fitch
Pinnacle West
Senior unsecured (a)	Baa3 (P)	BB+ (prelim)	N/A
Commercial paper	P-3	A-3	F-3
Outlook	Negative	Stable	Stable

APS
Senior unsecured	Baa2	BBB-	BBB
Secured lease obligation bonds	Baa2	BBB-	BBB-
Commercial paper	P-2	A-3	F-2
Outlook	Negative	Stable	Stable


(a)		Pinnacle West has a shelf registration under SEC Rule 415. Pinnacle West currently has no outstanding, rated senior unsecured securities. However, Moody’s assigns a provisional (P) rating and Standard & Poor’s assigns a preliminary (prelim) rating to the senior unsecured securities under such shelf registrations.

Debt Provisions

Pinnacle West’s and APS’ debt covenants related to their respective bank financing arrangements include debt to capitalization ratios. Certain of APS’ bank financing arrangements also include an interest coverage test. Pinnacle West and APS comply with these covenants and each anticipates it will continue to meet these and other significant covenant requirements. For both Pinnacle West and APS, these covenants require that the ratio of consolidated debt to total consolidated capitalization not exceed 65%. At March 31, 2007, the ratio was approximately 49% for Pinnacle West and 47% for APS. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements for APS. The interest coverage was

approximately 4.7 times under APS’ bank financing agreements as of March 31, 2007. Failure to comply with such covenant levels would result in an event of default which, generally speaking, would require the immediate repayment of the debt subject to the covenants and could cross-default other debt. See further discussion of “cross-default” provisions below.

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

All of Pinnacle West’s loan agreements contain “cross-default” provisions that would result in defaults and the potential acceleration of payment under these loan agreements if Pinnacle West or APS were to default under certain other material agreements. All of APS’ bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if APS were to default under certain other material agreements. Pinnacle West and APS do not have a material adverse change restriction for revolver borrowings.

See Note 4 for further discussions.

Capital Needs and Resources — By Company

Pinnacle West (Parent Company)

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

Our primary sources of cash are dividends from APS, external financings and cash distributions from our other subsidiaries, primarily SunCor. An existing ACC order requires APS to maintain a common equity ratio of at least 40% and prohibits APS from paying common stock dividends if the payment would reduce its common equity below that threshold. As defined in the ACC order, the common equity ratio is common equity divided by the sum of common equity and long-term debt, including current maturities of long-term debt. At March 31, 2007, APS’ common equity ratio, as defined, was approximately 53%.

Pinnacle West sponsors a qualified defined benefit and account balance pension plan and a non-qualified supplemental excess benefit retirement plan for the employees of Pinnacle West and our subsidiaries. IRS regulations require us to contribute a minimum amount to the qualified plan. We contribute at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of plan assets and our pension obligation. The assets in the plan are comprised of fixed-income, equity and short-term investments. Future year contribution amounts are dependent on fund performance and fund valuation assumptions. We contributed $47 million in 2006. The contribution to our pension plan in 2007 is estimated to be approximately $22 million, and the contribution to our other postretirement benefit plans in 2007 is estimated to be approximately $21 million. APS and other subsidiaries fund their share of the contributions. APS’ share is approximately 97% of both plans.

APS

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

Although provisions in APS’ articles of incorporation and ACC financing orders establish maximum amounts of preferred stock and debt that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. On December 15, 2006, APS filed a financing application with the ACC requesting an increase in APS’ current short-term and long-term debt authorizations. In the financing application, APS requested an increase to its current short-term debt authorization (7% of APS’capitalization) to 7% of APS’capitalization plus $500 million in order to meet its growing working capital needs. In addition, APS requested an increase to its current long-term debt authorization (approximately $3.2 billion) to approximately $4.2 billion in light of the projected growth of APS and its customer base and the resulting projected future financing needed to fund APS’ capital expenditure and maintenance program and other cash requirements.

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

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

Other Subsidiaries

During the past three years, SunCor funded its cash requirements with cash from operations and its own external financings. SunCor’s capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the capital expenditures table above for actual capital expenditures during the three months ended March 31, 2007 and projected capital expenditures for the next three years. SunCor expects to fund its future capital requirements with cash from operations and external financings.

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

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

See “Overview” above and Note 4 for discussion of Pinnacle West Marketing & Trading, the Company’s newly-formed marketing and trading subsidiary.

CRITICAL ACCOUNTING POLICIES

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues,

expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting, the determination of the appropriate accounting for our pension and other postretirement benefits and derivatives accounting. There have been no changes to our critical accounting policies since our 2006 Form 10-K. See “Critical Accounting Policies” in Item 7 of the 2006 Form 10-K for further details about our critical accounting policies.

OTHER ACCOUNTING MATTERS

PINNACLE WEST CONSOLIDATED – FACTORS AFFECTING
OUR FINANCIAL OUTLOOK

Factors Affecting Operating Revenues, Fuel and Purchased Power Costs

GeneralElectric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale power markets in the western United States. For the years 2004 through 2006, retail electric revenues comprised approximately 82% of our total electric operating revenues. Our electric operating revenues are affected by electricity sales volumes related to customer mix, customer growth, average usage per customer, electricity rates and tariffs, variations in weather from period to period, and amortization of PSA deferrals. Competitive retail sales of energy and energy-related products and services are made by APS Energy Services in certain western states that have opened to competition. Off-System Sales of excess generation output, purchased power and natural gas are included in regulated electricity segment revenues and related fuel and purchased power because the gross margin is credited to APS’ retail customers through the PSA. These revenue transactions are affected by the availability of excess generation or other energy resources and wholesale market conditions, including demand and prices. Competitive wholesale transactions are made by the marketing and trading group through structured trading opportunities involving matched sales and purchases of commodities.

Retail Rate ProceedingsThe key issue affecting Pinnacle West’s and APS’ financial outlook is the satisfactory resolution of APS’ retail rate proceedings pending before the ACC, which are discussed in greater detail in Note 5. The most significant pending retail rate proceedings are APS’ general rate case request and an application for a 1.9% PSA surcharge, or temporary rate

increase, related to incremental replacement power costs incurred by APS in 2005 in connection with unplanned outages at Palo Verde, which is subject to the ACC’s review of the unplanned outages. These matters have been consolidated procedurally and a decision on them by the ACC is expected in the second quarter of 2007. In addition, the ACC staff is conducting a review of the prudence of approximately $79 million in PSA deferrals related to 2006 unplanned outages at Palo Verde.

Fuel and Purchased Power CostsFuel and purchased power costs included on our income statements are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, transmission availability or constraints, prevailing market prices, new generating plants being placed in service in our market areas, our hedging program for managing such costs and, since April 1, 2005, PSA deferrals and the amortization thereof. See “Power Supply Adjustor” in Note 5 for information regarding the PSA, including PSA deferrals related to Palo Verde unplanned outages and reduced power operations that are the subject of ACC prudence reviews. APS’ recovery of PSA deferrals from its ratepayers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications.

Customer and Sales GrowthThe customer and sales growth referred to in this paragraph applies to Native Load customers and sales to them. Customer growth in APS’ service territory for the three-month period ended March 31, 2007 was 3.8% compared with the prior-year period. Such growth averaged 4.1% a year for the three years from 2004 through 2006; and we currently expect customer growth to average about 4.0% per year from 2007 to 2009. For the three years 2004 through 2006, APS’ actual retail electricity sales in kilowatt-hours grew at an average rate of 4.2%; adjusted to exclude effects of weather variations, such retail sales growth averaged 4.6% a year. We currently estimate that total retail electricity sales in kilowatt-hours will grow 3.2% on average, from 2007 through 2009, before the effects of weather variations. We currently expect our retail sales growth in 2007 to be below average because of potential effects on customer usage from the retail rate increases proposed by APS (see Note 5).

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

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

Wholesale Market ConditionsOur marketing and trading activities focus primarily on managing APS’ risks relating to fuel and purchased power costs in connection with its costs of serving Native Load customer demand. Our marketing and trading activities include, subject to specified parameters, marketing, hedging and trading in electricity, fuels and emission allowances and credits.

Other Factors Affecting Financial Results

Operations and Maintenance ExpensesOperations 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 ExpensesDepreciation and amortization expenses are impacted by net additions to utility plant and other property, which include generation construction, changes in depreciation and amortization rates, and changes in regulatory asset amortization.

Property TaxesTaxes other than income taxes consist primarily of property taxes, which are affected by the value of property in-service and under construction, assessed valuation ratios, and tax rates. The average property tax rate for APS, which currently owns the majority of our property, was 8.9% of assessed value for 2006 and 9.2% for 2005. We expect property taxes to increase as new power plants (including the Sundance Plant acquired in 2005) and additions to our transmission and distribution facilities are included in the property tax base.

Interest ExpenseInterest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels are expected to be our capital expenditures, long-term debt maturities, and internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop accruing capitalized interest on a project when it is placed in commercial operation.

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

SubsidiariesSunCor’s net income was $61 million in 2006, $56 million in 2005, and $45 million in 2004. See Note 17 for further discussion. We currently expect SunCor’s net income in 2007 will be between $30 million and $35 million. This estimate reflects a slow-down in the western United States residential real estate markets.

APS Energy Services’ and El Dorado’s historical results are not indicative of future performance.

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

Market Risks

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

Interest Rate and Equity Risk

We have exposure to changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and the market value of fixed income securities held by our nuclear

decommissioning trust fund. The nuclear decommissioning trust fund also has risks associated with the changing market value of its investments. Nuclear decommissioning costs are recovered in regulated electricity prices.

Commodity Price Risk

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

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

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

	•		Marketing and Trading – non-trading and trading derivative instruments of our competitive business activities.

The following tables show the pretax changes in mark-to-market of our non-trading and trading derivative positions for the three months ended March 31, 2007 and 2006 (dollars in millions):


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

Mark-to-market of net positions at end of period	$	46		$	85		$	104		$	131


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

The tables below show the fair value of maturities of our non-trading and trading derivative contracts (dollars in millions) at March 31, 2007 by maturities and by the type of valuation that is performed to calculate the fair values. See Note 1, “Derivative Accounting,” in Item 8 of our 2006 Form 10-K for more discussion of our valuation methods.

Regulated Electricity


																Years			Total fair
Source of Fair Value	2007			2008			2009			2010			2011			thereafter			value
Prices actively quoted	$	26		$	22		$	2		$	3		$	—		$	—		$	53
Prices provided by other external sources		12			—			—			—			—			—			12
Prices based on models and other valuation methods		(3	)		(2	)		(1	)		(4	)		(2	)		(7	)		(19	)

Total by maturity	$	35		$	20		$	1		$	(1	)	$	(2	)	$	(7	)	$	46

Marketing and Trading


															Years			Total fair
Source of Fair Value	2007			2008		2009			2010			2011			thereafter			value
Prices actively quoted	$	15		$	—	$	—		$	—		$	—		$	—		$	15
Prices provided by other external sources		37			21		—			—			2			2			62
Prices based on models and other valuation methods		(6	)		18		(1	)		(1	)		(1	)		(1	)		8

Total by maturity	$	46		$	39	$	(1	)	$	(1	)	$	1		$	1		$	85

The table below shows the impact that hypothetical price movements of 10% would have on the market value of our risk management and trading assets and liabilities included on Pinnacle West’s Condensed Consolidated Balance Sheets at March 31, 2007 and December 31, 2006 (dollars in millions):


	March 31, 2007					December 31, 2006
	Gain (Loss)					Gain (Loss)
	Price Up		Price			Price Up		Price
	10%		Down 10%			10%		Down 10%
Commodity
Mark-to-market changes reported in OCI (a):
Electricity	$	40	$	(40	)	$	38	$	(38	)
Natural gas		88		(88	)		80		(80	)

Total	$	128	$	(128	)	$	118	$	(118	)


(a)		These contracts are hedges of our forecasted purchases of natural gas and electricity. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged.

Credit Risk

We are exposed to losses in the event of non-performance or non-payment by counterparties. We have risk management and trading contracts with many counterparties, including one counterparty for which a worst case exposure represents approximately 11% of Pinnacle West’s risk management and trading assets as of March 31, 2007. See Note 1, “Derivative Accounting” in Item 8 of our 2006 Form 10-K for a discussion of our credit valuation adjustment policy. See Note 10 for further discussion of credit risk.

ARIZONA PUBLIC SERVICE COMPANY – RESULTS OF OPERATIONS

General

Throughout the following explanations of our results of operations, we refer to “gross margin.” Gross margin refers to electric operating revenues less fuel and purchased power costs. Gross margin is a “non-GAAP financial measure,” as defined in accordance with SEC rules. Exhibit 99.2 reconciles this non-GAAP financial measure to operating income, which is the most directly

comparable financial measure calculated and presented in accordance with GAAP. We view gross margin as an important performance measure of the core profitability of our operations. This measure is a key component of our internal financial reporting and is used by our management in analyzing our business. We believe that investors benefit from having access to the same financial measures that our management uses.

Deferred Fuel and Purchased Power Costs

APS settled its 2003 general retail rate case effective April 1, 2005. As part of the settlement, the ACC approved the PSA, which permits APS to defer for recovery or refund fluctuations in retail fuel and purchased power costs, subject to specified parameters. In accordance with the PSA, APS defers for future rate recovery 90% of the difference between actual retail fuel and purchased power costs and the amount of such costs currently included in base rates. APS’ recovery of PSA deferrals from its customers is subject to the ACC’s approval of annual PSA adjustments and periodic surcharge applications. (See “Power Supply Adjustor” in Note 5.)

Operating Results – Three-month period ended March 31, 2007 compared with three-month period ended March 31, 2006

APS’ net income for the three months ended March 31, 2007 was $4 million compared with a net loss $6 million for the comparable prior-year period. The $10 million increase was primarily due to the effects of cooler weather on retail sales; higher retail sales due to customer growth; and lower operations and maintenance expense related to generation. In addition, higher fuel and purchased power costs were partially offset by the deferral of such costs in accordance with the PSA. See “Deferred Fuel and Purchased Power Costs” above.

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


	Increase (Decrease)
	Pretax			After Tax
Gross margin:
Effects of cooler weather on retail sales	$	13		$	8
Higher retail sales due to customer growth, excluding weather effects		10			6
Higher fuel and purchased power costs due to increased prices (see “Deferred Fuel and Purchased Power Costs” above)		(14	)		(9	)
Increased deferred fuel and purchased power costs		12			7
Lower gains on marketing and trading		(9	)		(5	)
Miscellaneous items, net		3			3

Net increase in gross margin		15			10
Operations and maintenance decreases primarily due to:
Generation costs, including fewer power plant maintenance outages		4			2
Miscellaneous items, net		3			2
Higher interest expense, net of capitalized financing costs, primarily due to higher debt balances and higher rates		(5	)		(3	)
Miscellaneous items, net		(2	)		(1	)

Net increase in net income	$	15		$	10

Regulated Electricity Revenues

Regulated electricity revenues were $70 million higher for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of:

	•		a $51 million increase in retail revenues related to recovery of PSA deferrals, which had no earnings effect because of amortization of the same amount recorded as fuel and purchased power expense (see “Deferred Fuel and Purchased Power Costs” above);

	•		an $18 million increase in retail revenues due to cooler weather;

	•		a $13 million increase in retail revenues related to customer growth, excluding weather effects;

	•		a $5 million decrease in Off-System Sales due to lower sales volumes; and

	•		a $7 million decrease due to miscellaneous factors.

Marketing and Trading Revenues

Marketing and trading revenues were $9 million lower for the three months ended March 31, 2007 compared with the prior-year period primarily as a result of a decrease in mark-to-market gains on contracts for future delivery due to changes in forward prices.

ARIZONA PUBLIC SERVICE COMPANY – LIQUIDITY AND CAPITAL RESOURCES

Contractual Obligations

APS’ future contractual obligations have not changed materially from the amounts disclosed in Part II, Item 7 of the 2006 Form 10-K, with the exception of our aggregate fuel and purchased power commitments, which increased from approximately $2.5 billion at December 31, 2006 to $2.7 billion at March 31, 2007 as follows (dollars in billions):


2007	2008-2009		2010-2011		Thereafter		Total
$0.5	$	0.5	$	0.4	$	1.3	$	2.7

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

Upon adoption of FIN 48, APS is now required to include uncertain tax positions in the contractual obligations disclosure. APS has uncertain tax positions of approximately $179 million and expects to pay these in 2007. See Note 8.

FORWARD-LOOKING STATEMENTS

This document contains forward-looking statements based on current expectations, and neither Pinnacle West nor APS assumes any obligation to update these statements or make any further statements on any of these issues, except as required by applicable law. These forward-looking statements are often identified by words such as “estimate,” “predict,” “hope,” “may,” “believe,” “anticipate,” “plan,” “expect,” “require,” “intend,” “assume” and similar words. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by Pinnacle West or APS. In addition to the Risk Factors described in Item 1A of the 2006 Form 10-K, these factors include, but are not limited to:

	•		state and federal regulatory and legislative decisions and actions, including the outcome and timing of APS’ retail rate proceedings pending before the ACC;

	•		the timely recovery of PSA deferrals, including such deferrals in 2005 and 2006 associated with unplanned Palo Verde outages and reduced power operations that are the subject of ACC prudence reviews;

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

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

	•		market prices for electricity and natural gas;

	•		power plant performance and outages;

	•		transmission outages and constraints;

	•		weather variations affecting local and regional customer energy usage;

	•		customer growth and energy usage;

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

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

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

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

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

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

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

	•		technological developments in the electric industry;

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

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Pinnacle West Consolidated – Factors Affecting Our Financial Outlook” in Item 2 above for a discussion of quantitative and qualitative disclosures about market risks.

Item 4. CONTROLS AND PROCEDURES

(a) Disclosure Controls and Procedures

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

Pinnacle West’s management, with the participation of Pinnacle West’s Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of Pinnacle West’s disclosure controls and procedures as of March 31, 2007. Based on that evaluation, Pinnacle West’s Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, Pinnacle West’s disclosure controls and procedures were effective.

APS’ management, with the participation of APS’ Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of APS’ disclosure controls and procedures as of March 31, 2007. Based on that evaluation, APS’ Chief Executive Officer and Chief Financial Officer have concluded that, as of that date, APS’ disclosure controls and procedures were effective.

(b) Changes In Internal Control Over Financial Reporting

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

No change in Pinnacle West’s or APS’ internal control over financial reporting occurred during the fiscal quarter ended March 31, 2007 that materially affected, or is reasonably likely to materially affect, Pinnacle West’s or APS’ internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

See Note 12 in regard to pending or threatened litigation or other disputes.

Item 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in the 2006 Form 10-K, which could materially affect the business, financial condition or future results of APS and Pinnacle West. The risks described in the 2006 Form 10-K are not the only risks facing APS and Pinnacle West. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect the business, financial condition and/or operating results of APS and Pinnacle West.

Item 5. OTHER INFORMATION

Construction and Financing Programs

See “Liquidity and Capital Resources” in Part I, Item 2 of this report for a discussion of construction and financing programs of the Company and its subsidiaries.

Regulatory Matters

See Note 5 for a discussion of regulatory developments.

Environmental Matters

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

Federal Implementation Plan (“FIP”)

In September 1999, the EPA proposed a FIP to set air quality standards at certain power plants, including the Navajo Generating Station and the Four Corners Power Plant. On July 26, 2006, the Sierra Club sued the EPA in an attempt to force the EPA to issue a final FIP to limit emissions at the Four Corners Power Plant. On September 12, 2006, the EPA proposed a revised FIP to establish air quality standards at Four Corners and the Navajo Generating Station. On September 18, 2006, APS filed a motion to intervene in the Sierra Club’s lawsuit against the EPA, in order to assure that its interests are protected. On November 22, 2006, the court granted APS’ motion to intervene in the lawsuit. In December 2006, the court issued a consent decree signed by the Sierra Club and the EPA; the consent decree requires EPA to take “final action” on the proposed FIP by April 30, 2007. On April 30, 2007, the EPA issued the final FIP for Four Corners. The FIP essentially federalizes the requirements contained in the New Mexico State Implementation Plan, which Four Corners has historically followed. The FIP also includes a requirement to control fugitive dust within 18 months after the FIP becomes effective. (Fugitive dust is dust that is blown within the vicinity of the plant as a result of human activity, the wind, or both.) We do not believe the Four Corners FIP will have a material impact on our financial position, results of operations, cash flows or liquidity. The proposed FIP for the Navajo Generating Station is still pending. APS cannot currently predict the effect of this proposed FIP on the Company’s financial position, results of operations, cash flows or liquidity, or whether the proposed FIP will be adopted in its current form.

Regional Haze Rules

On April 22, 1999, the EPA announced final regional haze rules. These regulations require states to submit state implementation plans (SIPs) by December 2007 to demonstrate “reasonable progress” towards achieving natural visibility conditions in certain “Class I Areas,” including several on the Colorado Plateau. The SIP is required to consider and potentially apply “best available retrofit technology” (BART) for certain older major stationary sources. The rules allow nine western states and tribes to follow an alternate implementation plan and schedule for the Class I Areas. This alternate implementation plan is known as the Annex Rule.

On June 15, 2005, the EPA issued the Clean Air Visibility Rule, which amends the 1999 regional haze rules by providing guidelines, known as the BART guidelines, for states to use in determining which facilities must install controls and the type of controls the facilities must use. The EPA also issued a Revised Annex Rule on October 13, 2006 to address a previous challenge and court remand of that rule.

The Arizona Department of Environmental Quality (ADEQ) is currently undertaking a rulemaking process to amend its SIP to reconcile it with the Revised Annex Rule and to implement the Clean Air Visibility Rule requirements. As part of the rulemaking process, the ADEQ will require certain sources in the state to conduct BART analyses, potentially including Cholla and other APS plants. The ADEQ’s Regional Haze SIPs are due to EPA Region 9 in December 2007. In addition, we anticipate that EPA Region 9 may require Four Corners to conduct a BART analysis. The Company cannot currently predict the outcome of these proceedings.

Greenhouse Gas Accord

On February 26, 2007 five western states (Arizona, California, New Mexico, Oregon and Washington) entered into an accord to reduce greenhouse gas emissions from automobiles and certain industries, including utilities. The agreement requires the states to set emission goals within six months and determine a specific plan to meet such goals within eighteen months. While we continue to monitor the impact of this accord, we cannot predict its impact on our operations at this time.

Hazardous Air Pollutants Rule

ADEQ promulgated a Hazardous Air Pollutants (HAPs) rule that became effective on January 1, 2007. The HAPs rule requires certain sources of HAPs to evaluate and potentially apply pollution control technologies to limit HAPs emissions, or demonstrate through a risk management analysis that controls are not warranted. The rule is being challenged for its validity and currently does not apply in the counties in which APS has power plants. The APS plants potentially subject to HAPs regulation are the Saguaro Power Plant, located in Pinal County, and the Ocotillo and West Phoenix Power Plants, located in Maricopa County. State law requires these counties to adopt their own versions of the rule, and Maricopa County already is in the process of doing so. APS is monitoring the HAPs rule, its impact in the relevant counties and its validity. APS does not expect this matter to have a material adverse effect on its financial statements, results of operations, cash flows or liquidity.

Item 6. EXHIBITS

(a) Exhibits


*Exhibit No.*	*Registrant(s)*	*Description*
10.1	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 1), dated as of May 1, 2007

10.2	Pinnacle West APS	Amendment No. 5 to the Decommissioning Trust Agreement (PVNGS Unit 3), dated as of May 1, 2007

12.1	Pinnacle West	Ratio of Earnings to Fixed Charges

12.2	APS	Ratio of Earnings to Fixed Charges

12.3	Pinnacle West	Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend Requirements

31.1	Pinnacle West	Certificate of William J. Post, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.2	Pinnacle West	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.3	APS	Certificate of Jack E. Davis, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

31.4	APS	Certificate of Donald E. Brandt, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

32.1	Pinnacle West	Certification of Chief Executive Officer and Chief Financial Officer, pursuant to 18 U.S.C. Section 1850, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


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

99.1	Pinnacle West	Reconciliation of Operating Income to Gross Margin

99.2	APS	Reconciliation of Operating Income to Gross Margin

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


*Exhibit*				*Date*
*No.*	*Registrant(s)*	*Description*	*Previously Filed as Exhibit^a*	*Filed*
3.1	Pinnacle West	Articles of Incorporation, restated as of July 29, 1988	19.1 to Pinnacle West’s September 1988 Form 10-Q Report, File No. 1-8962	11-14-88

3.2	Pinnacle West	Pinnacle West Capital Corporation Bylaws, amended as of December 14, 2005	3.1 to Pinnacle West/APS December 9, 2005 Form 8-K Report, File Nos. 1-8962 and 1-4473	12-15-05

3.3	APS	Articles of Incorporation, restated as of May 25, 1988	4.2 to APS’ Form S-3 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report, File No. 1-4473	9-29-93

3.4	APS	Arizona Public Service Company Bylaws, amended as of June 23, 2004	3.1 to APS’ June 30, 2004 Form 10-Q Report, File No. 1-4473	8-9-04


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

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	PINNACLE WEST CAPITAL CORPORATION (Registrant)
Dated: May 9, 2007	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		Executive Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)

	ARIZONA PUBLIC SERVICE COMPANY (Registrant)
Dated: May 9, 2007	By:	/s/ Donald E. Brandt
		Donald E. Brandt
		President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)

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Pinnacle West Capital (PNW) 10-Q2007 Q1 Quarterly report

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