ARIZONA PUBLIC SERVICE CO - 10-Q Quarterly Report

FORM 10-Q

Securities and Exchange Commission

Washington, D.C. 20549

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2003

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-4473

ARIZONA PUBLIC SERVICE COMPANY

(Exact name of registrant as specified in its charter)

Arizona		86-0011170
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona		85072-3999
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:		(602) 250-1000

(Former name, former address and former fiscal year, if changed since last report)

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

Yes ý No o

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

Yes o No ý

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

Number of shares of common stock, $2.50 par value,

outstanding as of August 14, 2003: 71,264,947

The Registrant 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.

Glossary

ACC — Arizona Corporation Commission

ACC Staff — Staff of the Arizona Corporation Commission

ALJ — Administrative Law Judge

APS — Arizona Public Service Company, the Company

APS Energy Services — APS Energy Services Company, Inc., a subsidiary of Pinnacle West

CAISO — California Independent System Operator

CC&N — Certificate of Convenience and Necessity

Citizens — Citizens Communications Company

Company — Arizona Public Service Company

EITF — the FASB’s Emerging Issues Task Force

ERMC —Energy Risk Management Committee

FASB — Financial Accounting Standards Board

FERC — United States Federal Energy Regulatory Commission

FIN — FASB Interpretation

Financing Order — ACC order issued on April 4, 2003 relating to our request to provide financing or credit support to Pinnacle West Energy or Pinnacle West

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

Interim Financing Order — ACC order issued on November 22, 2002 relating to our request to provide financing or credit support to Pinnacle West

IRS — United States Internal Revenue Service

March 2003 10-Q — Arizona Public Service Company Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 2003

Moody’s — Moody’s Investors Service

MW — megawatt, one million watts

MWh — megawatt-hours, one million watts per hour

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

1999 Settlement Agreement — comprehensive settlement agreement related to the implementation of retail electric competition

NRC — United States Nuclear Regulatory Commission

OCI — other comprehensive income

Palo Verde — Palo Verde Nuclear Generating Station

PG&E — PG&E Corp.

Pinnacle West — Pinnacle West Capital Corporation, parent company of the Company

Pinnacle West Energy — Pinnacle West Energy Corporation, a subsidiary of Pinnacle West

PWEC Dedicated Assets — the following Pinnacle West Energy power plants, each of which is currently dedicated to our customers: Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and Saguaro Unit 3

PX — California Power Exchange

Rules — ACC retail electric competition rules

SCE — Southern California Edison Company

SEC — United States Securities and Exchange Commission

SFAS — Statement of Financial Accounting Standards

SNWA — Southern Nevada Water Authority

SPE — special-purpose entity

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

SunCor — SunCor Development Company, a subsidiary of Pinnacle West

System — non-trading energy related activities

T&D — transmission and distribution

Track A Order — ACC order dated September 10, 2002 regarding generation asset transfers and related issues

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

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

2002 10-K — the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2002

UniSource — UniSource Energy Corporation

VIE — variable interest entity

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30,
	2003			2002
	(Dollars in Thousands)

ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	512,461		$	507,711
Marketing and trading segment	107,992			2,369
Total	620,453			510,080

PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment	156,345			116,357
Marketing and trading segment	103,693			2,268
Total	260,038			118,625
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS	360,415			391,455

OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs	130,543			122,945
Depreciation and amortization	96,557			99,190
Income taxes	29,193			44,140
Other taxes	27,864			27,625
Total	284,157			293,900
OPERATING INCOME	76,258			97,555

OTHER INCOME (DEDUCTIONS):
Income taxes	294			2,005
Other income (Note 16)	3,362			929
Other expense (Note 16)	(3,743		)	(5,630		)
Total	(87		)	(2,696		)
INCOME BEFORE INTEREST DEDUCTIONS	76,171			94,859

INTEREST DEDUCTIONS:
Interest on long-term debt	35,166			32,301
Interest on short-term borrowings	1,463			1,162
Debt discount, premium and expense	829			698
Capitalized interest	(4,462		)	(3,741		)
Total	32,996			30,420

NET INCOME	$	43,175		$	64,439

See Notes to Condensed Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

	Six Months Ended June 30,
	2003			2002
	(Dollars in Thousands)

ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	899,629		$	891,452
Marketing and trading segment	199,550			13,062
Total	1,099,179			904,514

PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment	245,727			184,643
Marketing and trading segment	189,633			12,367
Total	435,360			197,010
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS	663,819			707,504

OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs	252,380			232,266
Depreciation and amortization	192,114			196,812
Income taxes	40,159			65,274
Other taxes	56,078			54,376
Total	540,731			548,728
OPERATING INCOME	123,088			158,776

OTHER INCOME (DEDUCTIONS):
Income taxes	798			2,370
Other income (Note 16)	4,825			3,859
Other expense (Note 16)	(6,259		)	(9,219		)
Total	(636		)	(2,990		)
INCOME BEFORE INTEREST DEDUCTIONS	122,452			155,786

INTEREST DEDUCTIONS:
Interest on long-term debt	68,134			64,038
Interest on short-term borrowings	2,722			2,299
Debt discount, premium and expense	1,549			1,340
Capitalized interest	(9,061		)	(8,093		)
Total	63,344			59,584

NET INCOME	$	59,108		$	96,202

See Notes to Condensed Financial Statements

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF INCOME

(Unaudited)

	Twelve Months Ended June 30,
	2003			2002
	(Dollars in Thousands)

ELECTRIC OPERATING REVENUES:
Regulated electricity segment	$	2,067,516		$	2,301,416
Marketing and trading segment	220,542			84,386
Total	2,288,058			2,385,802

PURCHASED POWER AND FUEL COSTS:
Regulated electricity segment	656,452			837,661
Marketing and trading segment	209,928			43,844
Total	866,380			881,505
OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS	1,421,678			1,504,297

OTHER OPERATING EXPENSES:
Operations and maintenance excluding purchased power and fuel costs	515,959			462,234
Depreciation and amortization	394,942			409,366
Income taxes	107,838			162,506
Other taxes	109,627			104,709
Total	1,128,366			1,138,815
OPERATING INCOME	293,312			365,482

OTHER INCOME (DEDUCTIONS):
Income taxes	4,576			4,659
Other income (Note 16)	7,103			9,860
Other expense (Note 16)	(17,366		)	(19,368		)
Total	(5,687		)	(4,849		)
INCOME BEFORE INTEREST DEDUCTIONS	287,625			360,633

INTEREST DEDUCTIONS:
Interest on long-term debt	132,558			126,336
Interest on short-term borrowings	5,839			4,230
Debt discount, premium and expense	3,097			2,655
Capitalized interest	(16,118		)	(15,233		)
Total	125,376			117,988

INCOME BEFORE ACCOUNTING CHANGE	162,249			242,645

Cumulative effect of a change in accounting for derivatives — net of income tax benefit of $8,099	—			(12,446		)

NET INCOME	$	162,249		$	230,199

See Notes to Condensed Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED BALANCE SHEETS

(Unaudited)

ASSETS

	June 30, 2003			December 31, 2002
	(Dollars in Thousands)

UTILITY PLANT:
Electric plant in service and held for future use	$	8,575,593		$	8,299,131
Less accumulated depreciation and amortization	3,354,846			3,442,571
Total	5,220,747			4,856,560
Construction work in progress	279,210			329,089
Intangible assets, net of accumulated amortization	108,301			93,259
Nuclear fuel, net of accumulated amortization	7,324			7,466
Utility plant — net	5,615,582			5,286,374

INVESTMENTS AND OTHER ASSETS:
Notes receivable from associated companies	497,500			—
Decommissioning trust accounts	205,841			194,440
Assets from risk management and trading activities — long-term	36,048			31,622
Other assets	15,307			19,964
Total investments and other assets	754,696			246,026

CURRENT ASSETS:
Cash and cash equivalents	63,287			42,549
Trust fund for bond redemption	54,150			—
Accounts receivable:
Service customers	176,581			136,945
Other	56,342			202,597
Allowance for doubtful accounts	(1,121		)	(1,341		)
Accrued utility revenues	106,480			72,915
Materials and supplies, at average cost	77,976			79,985
Fossil fuel, at average cost	33,649			28,185
Deferred income taxes	4,094			4,094
Assets from risk management and trading activities	96,497			39,616
Other	37,327			45,361
Total current assets	705,262			650,906

DEFERRED DEBITS:
Regulatory assets	200,073			241,045
Unamortized debt issue costs	21,665			16,696
Other	76,926			80,760
Total deferred debits	298,664			338,501

TOTAL ASSETS	$	7,374,204		$	6,521,807

See Notes to Condensed Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED BALANCE SHEETS

(Unaudited)

CAPITALIZATION AND LIABILITIES

	June 30, 2003			December 31, 2002
	(Dollars in Thousands)

CAPITALIZATION:
Common stock	$	178,162		$	178,162
Additional paid-in capital	1,246,804			1,246,804
Retained earnings	793,740			819,632
Accumulated other comprehensive loss:
Minimum pension liability adjustment	(61,599		)	(61,487		)
Derivative instruments	(1,634		)	(23,799		)
Common stock equity	2,155,473			2,159,312

Long-term debt less current maturities	2,475,631			2,217,340

Total capitalization	4,631,104			4,376,652

CURRENT LIABILITIES:

Current maturities of long-term debt	208,413			3,503
Accounts payable	134,758			118,133
Accrued taxes	145,174			82,557
Accrued interest	42,812			42,608
Customer deposits	43,049			39,865
Liabilities from risk management and trading activities	92,124			59,773
Other	53,106			51,820
Total current liabilities	719,436			398,259

DEFERRED CREDITS AND OTHER:
Deferred income taxes	1,219,839			1,225,552
Liabilities from risk management and trading activities — long-term	20,411			36,678
Unamortized gain — sale of utility plant	57,197			59,484
Customer advances for construction	44,832			45,513
Pension liability	143,285			156,442
Liability for asset retirement (Note 13)	226,878			—
Other	311,222			223,227
Total deferred credits and other	2,023,664			1,746,896

COMMITMENTS AND CONTINGENCIES (Note 12)

TOTAL LIABILITIES AND EQUITY	$	7,374,204		$	6,521,807

See Notes to Condensed Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY

CONDENSED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended June 30,
	2003			2002
	(Dollars in Thousands)
Cash Flows from Operating Activities:
Net Income	$	59,108		$	96,202
Items not requiring cash:
Depreciation and amortization	192,114			196,812
Nuclear fuel amortization	14,858			15,214
Deferred income taxes	(20,526		)	(30,722		)
Change in mark-to-market	(15,072		)	(4,586		)
Changes in certain current assets and liabilities:
Accounts receivable	106,571			(71,349		)
Accrued utility revenues	(33,565		)	(34,558		)
Materials, supplies and fossil fuel	(3,455		)	(5,167		)
Other current assets	8,034			(1,038		)
Accounts payable	25,121			(13,522		)
Accrued taxes	62,617			49,790
Accrued interest	204			461
Other current liabilities	4,469			581
Increase in regulatory assets	(4,565		)	(5,992		)
Change in risk management trading — assets	6,385			(26,141		)
Change in customer advances	(681		)	(1,695		)
Change in pension liability	(13,157		)	230
Change in other long-term assets	(10,629		)	(15,768		)
Change in other long-term liabilities	44,459			501
Net cash flow provided by operating activities	422,290			149,253

Cash Flows from Investing Activities:
Trust fund for bond redemption	(54,150		)	—
Capital expenditures	(212,021		)	(253,829		)
Capitalized interest	(9,061		)	(8,093		)
Loans to associated companies	(497,500		)	—
Other	(1,066		)	38,808
Net cash flow used for investing activities	(773,798		)	(223,114		)

Cash Flows from Financing Activities:
Issuance of long-term debt	491,654			369,930
Repayment and reacquisition of long-term debt	(34,408		)	(246,952		)
Short-term borrowings — net	—			26,838
Dividends paid on common stock	(85,000		)	(85,000		)

Net cash flow provided by financing activities	372,246			64,816
Net increase/(decrease) in cash and cash equivalents	20,738			(9,045		)
Cash and cash equivalents at beginning of period	42,549			16,821
Cash and cash equivalents at end of period	$	63,287		$	7,776

Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (excluding capitalized interest)	$	61,463		$	57,726
Income taxes	$	729		$	48,943

See Notes to Condensed Financial Statements.

ARIZONA PUBLIC SERVICE COMPANY

NOTES TO CONDENSED FINANCIAL STATEMENTS

(UNAUDITED)

1. Our unaudited condensed financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature with the exception of the cumulative effect of a change in accounting for derivatives (see Note 10) and the transition adjustment for asset retirement obligations (see Note 13). We suggest that these condensed financial statements and notes to condensed financial statements be read along with the financial statements and notes to financial statements included in our 2002 10-K. We have reclassified certain prior year amounts to conform to the current year presentation (see Note 10).

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

3. We are a wholly-owned subsidiary of Pinnacle West.

4. On April 7, 2003, we redeemed approximately $33 million of our First Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, we redeemed approximately $54 million of our First Mortgage Bonds, 7.25% Series due 2023.

On May 12, 2003, we issued $500 million of debt as follows: $300 million aggregate principal amount of our 4.650% Notes due 2015 and $200 million aggregate principal amount of our 5.625% Notes due 2033. Also on May 12, 2003, we made a $500 million loan to Pinnacle West Energy, and Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund Pinnacle West’s repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. See “ACC Financing Orders” in Note 5 for additional information.

5. Regulatory Matters

State

Overview

On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. On September 23, 1999, the ACC approved a comprehensive settlement agreement among us and various parties related to the implementation of retail electric competition in Arizona. On September 10, 2002, the ACC issued the Track A Order, which, among other things, directed us not to transfer our generation assets to Pinnacle West Energy, as previously required under the Rules and the 1999 Settlement Agreement. See “Track A Order” below. The Track A Order and legal challenges to the Rules have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona.

On March 14, 2003, the ACC issued the Track B Order, which required us to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. Pinnacle West Energy bid on and entered into a contract to supply most of our requirements in the summer months through September 2006. See “Track B Order” below.

On April 4, 2003, the ACC issued the Financing Order authorizing us to lend up to $500 million to Pinnacle West Energy. See “ACC Financing Orders” below. On May 12, 2003, we issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund the repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. See Note 4.

On June 27, 2003, we filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in our annual retail electricity revenues, to become effective July 1, 2004. The major components of the request are described under “General Rate Case and Retail Rate Adjustment Mechanisms” below.

1999 Settlement Agreement

The following are the major provisions of the 1999 Settlement Agreement, as approved by the ACC:

• We have reduced rates for standard-offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. Based on the price reductions authorized in the 1999 Settlement Agreement, there were retail price decreases of approximately $24 million ($14 million after taxes), effective July 1, 1999; approximately $28 million ($17 million after taxes), effective July 1, 2000; approximately $27 million ($16 million after taxes), effective July 1, 2001; approximately $28 million ($17 million after taxes), effective July 1, 2002; and approximately $29 million ($18 million after taxes), effective July 1, 2003. For customers having loads of three MW or greater, standard-offer rates have been reduced in varying annual increments that total 5% in the years 1999 through 2002.

• Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004.

• There is a moratorium on retail price changes for standard-offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor us is prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms; material changes in our cost of service for ACC-regulated services resulting

from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders.

• We will be permitted to defer for later recovery prudent and reasonable costs of complying with the Rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the “provider of last resort” and standard-offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. See “General Rate Case and Retail Rate Adjustment Mechanisms” below.

• Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the Rules (see “Retail Electric Competition Rules” below), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001. The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory.

• Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to a 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value (in 1999 dollars). The 1999 Settlement Agreement also stated that we will not be allowed to recover $183 million net present value (in 1999 dollars) of the $533 million. The 1999 Settlement Agreement provides that we will have the opportunity to recover $350 million net present value (in 1999 dollars) through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery of the $350 million due to sales volume variances. As discussed below under “General Rate Case and Retail Rate Adjustment Mechanisms,” we are seeking to recover amounts written off by us as a result of the 1999 Settlement Agreement.

• The 1999 Settlement Agreement required us to form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) our competitive electric assets and services no later than December 31, 2002. The 1999 Settlement Agreement provided that we would be allowed to defer and later collect, beginning July 1, 2004, 67% of our costs to accomplish the required transfer of generation assets to an affiliate. However, as noted

above and discussed in greater detail below, in 2002 the ACC unilaterally modified this aspect of the 1999 Settlement Agreement by issuing an order preventing us from transferring our generation assets. We are seeking to recover all the costs we incurred in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. See “General Rate Case and Retail Rate Adjustment Mechanisms” below.

Retail Electric Competition Rules

The Rules approved by the ACC included the following major provisions:

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

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

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

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

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

• Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive electric assets and services to an unaffiliated party or parties or to a separate corporate affiliate or affiliates. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our competitive electric assets and services to affiliates no later than December 31, 2002. However, as noted above and discussed in greater detail below, in 2002 the ACC reversed its decision, as reflected in the Rules, to require us to transfer our generation assets.

Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, we must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement.

On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was

not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of our property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have appealed the ruling to the Arizona Court of Appeals, as a result of which the Superior Court’s ruling is automatically stayed pending further judicial review. That appeal is still pending. In a similar appeal concerning the issuance of competitive telecommunications CC&N’s, the Arizona Court of Appeals invalidated rates for competitive carriers due to the ACC’s failure to establish a fair value rate base for such carriers. The Arizona Supreme Court agreed that the ACC had to determine a fair value rate base but vacated the Court of Appeals’ requirement that competitive rates be set based only on such fair value rate base.

Provider of Last Resort Obligation

Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are the “provider of last resort” for standard-offer, full-service customers under rates that have been approved by the ACC. These rates are established until at least July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing on reasonable terms; material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws; regulatory requirements; or judicial decisions, actions or orders. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. In the event of shortfalls due to unforeseen increases in load demand or generation or transmission outages, we may need to purchase additional supplemental power in the wholesale spot market. Unless we are able to obtain an adjustment of our rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that we would be able to fully recover the costs of this power. See “General Rate Case and Retail Rate Adjustment Mechanisms” below for a discussion of retail rate adjustment mechanisms that were the subject of ACC hearings in April 2003.

Track A Order

On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things:

• reversed its decision, as reflected in the Rules, to require us to transfer our generation assets either to an unrelated third party or to a separate corporate affiliate; and

• unilaterally modified the 1999 Settlement Agreement, which authorized the transfer of our generating assets, and directed us to cancel our activities to transfer our generation assets to Pinnacle West Energy.

On November 15, 2002, we filed appeals of the Track A Order in the Maricopa County, Arizona Superior Court and in the Arizona Court of Appeals. Arizona Public Service Company vs. Arizona Corporation Commission, CV 2002-0222 32. Arizona Public Service Company vs. Arizona Corporation Commission, 1CA CC 02-0002. On December 13, 2002, we and the ACC Staff agreed to principles for resolving certain issues raised by us

in our appeals of the Track A Order. We and the ACC are the only parties to the Track A Order appeals. The major provisions of the principles include, among other things, the following:

• We and the ACC Staff agreed that it would be appropriate for the ACC to consider the following matters in our general rate case, which was filed on June 27, 2003:

• the generating assets to be included in our rate base, including the question of whether the PWEC Dedicated Assets should be included in our rate base;

• the appropriate treatment of the $234 million pretax asset write-off agreed to by us as part of the 1999 Settlement Agreement; and

• the appropriate treatment of costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy.

• Upon the ACC’s issuance of a final decision that is no longer subject to appeal approving our request to provide $500 million of financing or credit support to Pinnacle West Energy or Pinnacle West, with appropriate conditions, our appeals of the Track A Order would be limited to the issues described in the preceding bullet points, each of which would be presented to the ACC for consideration prior to any final judicial resolution. As noted below, the ACC issued the Financing Order on April 4, 2003. The Financing Order is final and no longer subject to appeal. As a result, our appeals of the Track A Order will be limited to the issues described in the preceding bullet points.

On February 21, 2003, a Notice of Claim was filed with the ACC and the Arizona Attorney General on behalf of Pinnacle West, Pinnacle West Energy and us to preserve their and our rights relating to the Track A Order. As of April 22, 2003, the Notice of Claim was deemed denied with respect to the ACC and the Arizona Attorney General, and Pinnacle West, Pinnacle West Energy and we may now pursue the claim in court.

Track B Order

On March 14, 2003, the ACC issued the Track B Order, which required us to solicit bids for certain estimated amounts of capacity and energy for periods beginning July 1, 2003. For 2003, we were required to solicit competitive bids for about 2,500 MW of capacity and about 4,600 gigawatt-hours of energy, or approximately 20% of our total retail energy requirements. The bid amounts are expected to increase in 2004 and 2005 based largely on growth in our retail load and our retail energy sales. The Track B Order also confirmed that it was “not intended to change the current rate base status of [APS’] existing assets.”

The order recognizes our right to reject any bids that are unreasonable, uneconomical or unreliable. The ACC Staff and an independent monitor participated in the Track B procurement process. The Track B Order also contains requirements relating to standards of conduct between us and any affiliate of ours participating in the competitive solicitation, requires that we treat bidders in a non-discriminatory manner and requires us to file a protocol regarding short-term and emergency procurements. The order permits the provision of corporate oversight, support and governance as long as such activities do not favor Pinnacle West Energy in the procurement process or provide Pinnacle West Energy with our confidential bidding information that is not available to other bidders. The order directs us to evaluate bids on cost, reliability and reasonableness. The decision requires bidders to allow the ACC to inspect their plants and requires assurances of appropriate competitive market conduct from senior officers of such bidders. Following the solicitation, we will prepare a report evaluating environmental issues relating to the procurement and a series of workshops on environmental risk management will be commenced thereafter.

We issued requests for proposals in March 2003 and by May 6, 2003, we entered into contracts to meet all or a portion of our requirements for the years 2003 through 2006 as follows:

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

(2) PPL EnergyPlus, LLC agreed to provide 112 MW in July through September of 2003 and 150 MW in June through September of 2004 and 2005, by means of a unit contingent contract.

(3) Panda Gila River LP agreed to provide 450 MW in October of 2003 and 2004 and May of 2004 and 2005, and 225 MW from November 2003 through April 2004 and from November 2004 through April 2005, by means of firm call options.

ACC Financing Orders

On April 4, 2003, the ACC issued the Financing Order authorizing us to lend up to $500 million to Pinnacle West Energy, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate (the “APS Loan”), subject to the following principal conditions:

• any debt issued by us pursuant to the order must be unsecured;

• the APS Loan must be callable and secured by the PWEC Dedicated Assets;

• the APS Loan must bear interest at a rate equal to 264 basis points above the interest rate on our debt that could be issued and sold on equivalent terms (including, but not limited to, maturity and security);

• the 264 basis points referred to in the previous bullet point will be capitalized as a deferred credit and used to offset retail rates in the future, with the deferred credit balance bearing an interest rate of six percent per annum;

• the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC;

• any demonstrable increase in our cost of capital as a result of the transaction (such as from a decline in bond rating) will be excluded from future rate cases;

• we must maintain a common equity ratio of at least forty percent and may not pay common dividends if such payment would reduce our common equity ratio below that threshold, unless otherwise waived by the ACC. The ACC will process any waiver request within sixty days, and for this sixty-day period this condition will be suspended. However, this condition, which will continue indefinitely, will not be permanently waived without an order of the ACC; and

• certain waivers of the ACC’s affiliated interest rules previously granted to us and our affiliates will be temporarily withdrawn and, during the term of the APS Loan, neither Pinnacle West nor Pinnacle West Energy may reorganize or restructure, acquire or divest assets, or form, buy or sell affiliates (each, a “Covered Transaction”), or pledge or otherwise encumber the Pinnacle West Energy assets without prior ACC approval, except that the foregoing restrictions will not apply to the following categories of Covered Transactions:

• Covered Transactions less than $100 million, measured on a cumulative basis over the calendar year in which the Covered Transactions are made;

• Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCor’s anticipated accelerated asset sales activity during those years;

• Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy’s (a) West Phoenix Unit 5, located in Phoenix and (b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and

• Covered Transactions related to the sale of 25% of the Silverhawk plant to SNWA if SNWA exercises its existing purchase option to do so.

The ACC also ordered the ACC Staff to conduct an inquiry into our and our affiliates’ compliance with the retail electric competition and related rules and decisions. On June 13, 2003, we submitted our report on these matters to the ACC Staff.

On May 12, 2003, we issued $500 million of debt pursuant to the Financing Order and made a $500 million loan to Pinnacle West Energy. Pinnacle West Energy distributed the net proceeds of that loan to Pinnacle West to fund the repayment of a portion of the debt incurred to finance the construction of the PWEC Dedicated Assets. See Note 4.

On November 22, 2002, the ACC issued an order (the “Interim Financing Order”) approving our request to permit us to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West’s short-term debt, subject to certain conditions. As of June 30, 2003, there were no borrowings outstanding under this financing arrangement.

General Rate Case and Retail Rate Adjustment Mechanisms

As noted above, on June 27, 2003, we filed a general rate case with the ACC and requested a $175.1 million, or 9.8%, increase in our annual retail electricity revenues, to become effective July 1, 2004. In this rate case, we updated our cost of service and rate design.

Major Components of the Request The major reasons for the request include:

• complying with the provisions of the 1999 Settlement Agreement;

• incorporating significant increases in fuel and purchased power costs, including results of purchases through the ACC’s Track B procurement process;

• recognizing changes in our cost of service, cost allocation and rate design;

• obtaining rate recognition of the PWEC Dedicated Assets;

• recovering $234 million written off by us as a result of the 1999 Settlement Agreement; and

• recovering restructuring and compliance costs associated with the ACC’s Rules.

Requested Rate Increase The requested rate increase totals $175.1 million, or 9.8%, and is comprised of the following items (dollars in millions):

	Annual Revenue		Percent

Increase in base rates	$	166.8	9.3	%
Competition rules compliance charge	8.3		0.5	%
Total increase	$	175.1	9.8	%

Test Year The filing is based on an adjusted historical test year ended December 31, 2002.

Cost of Capital The proposed weighted average cost of capital for the test year ended December 31, 2002 is 8.67%, including an 11.5% return on equity.

Rate Base The request is based on a rate base of $4.2 billion, calculated using Original Cost Less Depreciation (“OCLD”) methodology. The OCLD rate base approximates the ACC-jurisdictional portion of the net book value of utility plant, net of accumulated depreciation and deferred taxes, as of December 31, 2002, except as set forth below.

The requested rate base includes the PWEC Dedicated Assets, with a total combined capacity of approximately 1,800 MW. These assets were included at their estimated July 1, 2004 net book value. Upon approval of the request, the PWEC Dedicated Assets would be transferred to us from Pinnacle West Energy.

The filing also includes calculated amounts for Fair Value Rate Base and Replacement Cost New Depreciated (“RCND”) rate base. The ACC is required by the Arizona Constitution to make a finding of Fair Value Rate Base, which is defined as the arithmetic average of OCLD rate base and RCND rate base.

Recovery of Previous $234 Million Write-Off The request includes recovery, over a fifteen year period, of the write-off of $234 million pretax of regulatory assets by us as a result of the 1999 Settlement Agreement. See “1999 Settlement Agreement” above.

Estimated Timeline We have asked the ACC to approve the requested rate increase by July 1, 2004. The Company expects the ACC to issue procedural schedules during the next several months detailing the timeline for addressing the request.

The general rate case also addresses the implementation of rate adjustment mechanisms that were the subject of ACC hearings in April 2003. The rate adjustment mechanisms, which were authorized as a result of the 1999 Settlement Agreement, would allow us to recover several types of costs, the most significant of which are power supply costs (fuel and purchased power costs) and costs associated with complying with the Rules. We assume that the ACC will make a decision in this general rate case by the end of 2004.

Federal

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

On July 31, 2002, the FERC issued a Notice of Proposed Rulemaking for Standard Market Design for wholesale electric markets. Voluminous comments and reply comments were filed on virtually every aspect of the proposed rule. On April 28, 2003, the FERC Staff issued an additional white paper on the proposed Standard Market Design. The white paper discusses several policy changes to the proposed Standard Market Design, including a greater emphasis on flexibility for regional needs. The FERC invited comments on the white paper, but has not yet set a due date for filing comments. We are reviewing the proposed rulemaking and cannot currently predict what, if any, impact there may be to the

Company if the FERC adopts the proposed rule or any modifications proposed in the comments.

General

The regulatory developments and legal challenges to the Rules discussed in this Note have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment.

6. Nuclear Insurance

The Palo Verde participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we 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 $10 million per incident. Based on our interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $88 million, with an annual payment limitation of approximately $9 million.

The Palo Verde participants maintain “all risk” (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions.

7. Business Segments

We have two principal business segments (determined by services and the regulatory environment):

• our regulated electricity segment, which consists of regulated traditional retail and wholesale electricity businesses and related activities, and includes electricity generation, transmission and distribution; and

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading. See Note 18

for information about the transfers of the marketing and trading division and more information regarding our marketing and trading activities.

Financial data for our business segments follows (dollars in millions):

	Three Months Ended June 30,				Six Months Ended June 30,				Twelve Months Ended June 30,
	2003		2002		2003		2002		2003		2002
Operating Revenues:
Regulated electricity	$	512	$	508	$	900	$	892	$	2,067	$	2,302
Marketing and trading	108		2		199		13		221		84
Total	$	620	$	510	$	1,099	$	905	$	2,288	$	2,386

Net Income:
Regulated electricity	$	41	$	64	$	53	$	96	$	156	$	218
Marketing and trading (a)	2		—		6		—		6		12
Total	$	43	$	64	$	59	$	96	$	162	$	230

(a) In the twelve months ended June 30, 2002, we recorded a $12 million after tax charge in July 2001 for the cumulative effect of a change in accounting for derivatives as required by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.”

8. Accounting Matters

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133. The provisions of SFAS No. 149 that relate to previously issued SFAS No. 133 derivatives implementation guidance should continue to be applied in accordance with the effective dates of the original implementation guidance. In general, other provisions are applied prospectively to contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. We are currently evaluating the impacts of SFAS No. 149 on our financial statements.

In June 2003, the FASB’s Derivatives Implementation Group (DIG) issued DIG Issue C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” To qualify for a normal purchases and sales scope exception under SFAS No. 133 the pricing in a contract must be clearly and closely related to the item being purchased or sold. DIG Issue C20 provides guidance on the clearly and closely related criterion and supercedes previous guidance. The new rules allow the use of broad-based market indicators in certain circumstances.

DIG Issue C20 is effective for us on October 1, 2003. It is to be applied prospectively to existing and future contracts. A special transition adjustment is required for an entity that had been applying the normal scope exception to a derivative contract that contained a price adjustment feature that was not based on the fair value of the item being purchased or sold or was not an ingredient or direct factor in its production. That entity should record a cumulative

effect adjustment to net income for the fair value of the contract at the implementation date of DIG Issue C20. While we continue to evaluate this new guidance, we currently do not expect DIG Issue C20 to have a material impact on our financial statements.

In May 2003, the FASB ratified EITF 01-8, “Determining Whether an Arrangement Contains a Lease.” This issue provides guidance for determining whether an arrangement contains a lease that is within the scope of SFAS No. 13, “Accounting for Leases.” Under EITF 01-8, an arrangement contains a lease if the specific property, plant or equipment has been explicitly or implicitly identified and the arrangement conveys to the purchaser the right to use the property, plant or equipment as defined in this issue. For us, the new guidance is effective for arrangements committed to or modified after June 30, 2003. We currently do not expect EITF 01-8 to have a material impact on our financial statements.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” This statement requires that an issuer classify certain financial instruments, which were previously classified as equity, as liabilities (or assets in some circumstances). This statement was effective immediately for financial instruments entered into or modified after May 31, 2003 and otherwise is effective for all other financial instruments beginning July 1, 2003. While we continue to evaluate this new guidance, we currently do not expect SFAS No. 150 to have a material impact on our financial statements.

In November 2002, the EITF reached a consensus on EITF 00-21, “Revenue Arrangements with Multiple Deliverables.” EITF 00-21 addresses certain aspects of the accounting by a vendor for arrangements under which it will perform multiple revenue-generating activities. EITF 00-21 specifically addresses how to determine whether an arrangement has identifiable, separable revenue-generating activities. EITF 00-21 does not address when the criteria for revenue recognition are met or provide guidance on the appropriate revenue recognition convention. For us, EITF 00-21 is effective for revenue arrangements entered into after June 30, 2003. We currently do not expect EITF 00-21 to have a material impact on our financial statements.

In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), “Accounting for Certain Costs Related to Property, Plant, and Equipment.” This proposed SOP would create a project timeline framework for capitalizing costs related to property, plant and equipment construction. It would require that property, plant and equipment assets be accounted for at the component level and require administrative and general costs incurred in support of capital projects to be expensed in the current period. We are waiting for further guidance from the FASB and the AICPA on the timing of the final guidance.

See the following Notes for other new accounting standards:

• Note 9 for a new interpretation (FIN No. 46) related to VIEs;

• Note 10 for a new EITF issue (EITF 02-3) related to accounting for energy trading contracts;

• Note 13 for a new accounting standard (SFAS No. 143) on asset retirement obligations;

• Note 15 for a new accounting standard (SFAS No. 148) on stock-based compensation; and

• Note 17 for a new interpretation (FIN No. 45) on guarantees.

9. Variable Interest Entities

In January 2003, the FASB issued FIN No. 46, “Consolidation of Variable Interest Entities.” FIN No. 46 requires that we consolidate a VIE if we have a majority of the risk of loss from the VIE’s activities or we are entitled to receive a majority of the VIE’s residual returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003. We currently do not expect FIN No. 46 to have a material impact on our financial statements.

In 1986, we entered into agreements with three separate SPE 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.While we continue to evaluate the guidance, we currently do not expect that we will be required to consolidate the Palo Verde SPEs under FIN No. 46.

We are exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that we do 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), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants, and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of June 30, 2003, we would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

10. Derivative Instruments and Energy Trading Activities

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. As part of our risk management program, we enter into derivative transactions 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.

For the twelve months ended June 30, 2002, we recorded a $12 million after tax charge in net income and a $8 million after tax credit in common stock equity (as a component of other comprehensive income (loss)), both as cumulative effects of a change in accounting for derivatives, as required by SFAS No. 133. The charge primarily resulted from electricity option contracts. The credit resulted from unrealized gains on cash flow hedges.

We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. The impact of this guidance was immaterial to our financial statements. Our energy trading contracts that are derivatives are accounted for at fair value under SFAS No. 133. Contracts that do not meet the definition of a derivative are accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received. Additionally, all gains and losses (realized and unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Condensed Statements of Income on a net basis. Derivative instruments used for non-trading activities are accounted for in accordance with SFAS No. 133.

EITF 02-3 requires that derivatives held for trading purposes, whether settled financially or physically, be reported in the income statement on a net basis. Conversely, all non-trading contracts and derivatives are to be reported gross on the income statement.

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

• System - non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements of our regulated electricity business segment; and

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

The changes in derivative fair value of our system positions included in the Condensed Statements of Income for the three, six and twelve months ended June 30, 2003 and 2002 are comprised of the following (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,					Twelve Months Ended June 30,
	2003			2002			2003		2002			2003			2002
Gains on the ineffective portion of derivatives qualifying for hedge accounting (a)	$	4,329		$	3,227		$	5,893	$	3,115		$	11,260		$	928
Losses from the discontinuance of cash flow hedges	—			—			—		(44		)	(9,162		)	(1,871		)
Gains (losses) from non-hedge derivatives	948			(1,857		)	6,207		(3,113		)	(3,325		)	(2,487		)
Prior period mark-to-market losses (gains) realized upon delivery of commodities	(6,289		)	2,926			4,154		6,739			7,827			26,208
Total pretax gain (loss)	$	(1,012	)	$	4,296		$	16,254	$	6,697		$	6,600		$	22,778

(a) Time value component of options excluded from assessment of hedge effectiveness.

As of June 30, 2003, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is approximately 18 months. During the twelve months ending June 30, 2004, we estimate that a net loss of $2 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transactions.

The following table summarizes our assets and liabilities from risk management and trading activities at June 30, 2003 and December 31, 2002 (dollars in thousands):

June 30, 2003

	Current Assets		Investments		Current Liabilities			Other Liabilities			Net Asset/ (Liability)
Mark-to-Market:
Marketing and Trading	$	6,254	$	181	$	(5,748	)	$	(1,868	)	$	(1,181	)
System	90,243		17,601		(86,376		)	(18,543		)	2,925
Emission allowances — at cost	—		18,266		—			—			18,266
Total	$	96,497	$	36,048	$	(92,124	)	$	(20,411	)	$	20,010

December 31, 2002

	Current Assets		Investments		Current Liabilities			Other Liabilities			Net Asset/ (Liability)
Mark-to-Market:
Marketing and Trading	$	—	$	—	$	—		$	—		$	—
System	39,616		6,971		(59,773		)	(36,678		)	(49,864		)
Emission allowances — at cost	—		24,651		—			—			24,651
Total	$	39,616	$	31,622	$	(59,773	)	$	(36,678	)	$	(25,213	)

Cash or collateral may be required to serve as collateral against our open positions on certain energy-related contracts. No collateral was provided at June 30, 2003. Collateral provided was $5 million at December 31, 2002 and is included in investments and other assets on the Condensed Balance Sheet. Collateral held was $8 million at June 30, 2003 and $4 million at December 31, 2002 and is included in other liabilities on the Condensed Balance Sheet.

11. Comprehensive Income

Components of comprehensive income for the three, six and twelve months ended June 30, 2003 and 2002, are as follows (dollars in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,					Twelve Months Ended June 30,
	2003		2002		2003			2002		2003			2002

Net income	$	43,175	$	64,439	$	59,108		$	96,202	$	162,249		$	230,199
Other comprehensive income (loss):
Minimum pension liability adjustment, net of tax	—		—		(112		)	—		(60,633		)	(966		)
Cumulative effect of a change in accounting for derivatives, net of tax	—		—		—			—		—			7,801
Unrealized gain on derivative instruments, net of tax(a)	11,976		2,089		20,628			26,855		32,538			15,304
Reclassification of realized (gain) loss to income, net of tax (b)	3,457		1,076		1,537			1,618		954			(6,319		)
Total other comprehensive income (loss)	15,433		3,165		22,053			28,473		(27,141		)	15,820

Comprehensive income	$	58,608	$	67,604	$	81,161		$	124,675	$	135,108		$	246,019

(a) These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted electricity and gas requirements to serve Native Load.

(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

California Energy Market Issues and Refunds in the Pacific Northwest

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. This order calls for a hearing, with findings of fact due to the FERC after the CAISO and PX provide necessary historical data. The FERC directed an ALJ to make findings of fact with respect to: (1) the mitigated price in each hour of the refund period; (2) the amount of refunds owed by each supplier according to the methodology established in the order; and (3) the amount currently owed to each supplier (with separate quantities due from each entity) by the

CAISO, the California Power Exchange, the investor-owned utilities and the State of California.

We were a seller and a purchaser in the California markets at issue, and to the extent that refunds are ordered, we should be a recipient as well as a payor of such amounts. On December 12, 2002, an ALJ issued Proposed Findings of Fact with respect to the refunds. On March 26, 2003, the FERC adopted the great majority of the proposed findings, revising only the calculation of natural gas prices for the final determination of mitigated prices in the California markets. Sellers who may actually have paid more for natural gas than the proxy prices adopted by the FERC are required to submit necessary data to the FERC, after which a technical conference will be held. Finalization of refund calculations is expected by the end of 2003. Subsequent to the foregoing refund decision by the FERC, the California parties filed a request for rehearing asking the FERC to expand the time period and transactions covered by the refund proceeding and provide for approximately $3 billion in additional refunds relating to sales by all sellers in the California markets. We do not anticipate material changes in our exposure and still believe, subject to the finalization of the revised proxy prices, that we will be entitled to a net refund.

On November 20, 2002, the FERC reopened discovery in these proceedings pursuant to instructions of the United States Court of Appeals for the Ninth Circuit that the FERC permit parties to offer additional evidence of potential market manipulation for the period January 1, 2000 through June 20, 2001. Parties submitted additional evidence and proposed findings, which the FERC continues to consider. On a parallel track, in March 2003, FERC made public a final report on price manipulation in Western markets, prepared by its staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during the 2000 to 2001 time period, including us, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the CAISO tariff. The report also recommended that the FERC issue an order to show cause why these transactions did not violate the CAISO tariff with potential disgorgement of any unjust profits.

On June 25, 2003, the FERC issued an order finding that certain identified entities appear to have potentially participated in activities that constitute gaming and/or anomalous market behavior in violation of the CAISO’s and PX’s tariffs during the period of January 1, 2000 to June 20, 2001. The FERC directed the CAISO, within 21 days of the date of the order to provide the identified entities with all of the specific transaction data for each of the specified potential gaming practices, and directed the identified entities to file responses within 45 days thereafter, absent a settlement. The FERC also established a hearing proceeding to be held before an ALJ for the identified entities to show cause, why they should not be found to have engaged in gaming practices in violation of the CAISO and PX tariffs. We were named as an identified entity in this order because of evidence of possible use of “paper trading” (the buy back of ancillary services) and "false import" (ricochet or megawatt laundering) strategies. The show cause submissions are due to the FERC on September 2, 2003. Based on our review of the allegations, as outlined in the terms of the order, we believe that we were not improperly engaged in any of the identified gaming practices.

Also in June 2003, the FERC initiated an investigation of all bids in the CAISO and PX markets above $250 per MWh during the period May 1, 2000 through October 1, 2000.

The FERC Office of Market Oversight and Investigations has issued data requests and is required to report back to the FERC by year-end 2003. Although we bid over $250 per MWh during the time period in question, we believe that our bids were not improper.

With regard to the Pacific Northwest, the FERC, in 2001, ordered an evidentiary proceeding to discuss and evaluate possible refunds. The FERC required that the record establish the volume of the transactions, the identification of the net sellers and net buyers, the price and terms and conditions of the sales contracts and the extent of potential refunds. On September 24, 2001, an ALJ concluded that prices in the Pacific Northwest during the period December 25, 2000 through June 20, 2001 were the result of a number of factors in addition to price signals from the California markets, including the shortage of supply, excess demand, drought and increased natural gas prices. Under these circumstances, the ALJ ultimately concluded that the prices in the Pacific Northwest were not unreasonable or unjust and refunds should not be ordered in this proceeding. On December 19, 2002, the FERC opened a new discovery period to permit the parties to offer additional evidence for the period January 1, 2000 through June 20, 2001. Additional evidence was submitted in March 2003. In June 2003, the FERC issued a final order terminating this proceeding without refunds. Certain parties have sought rehearing of the FERC’s final order.

Although the FERC has not calculated the specific refund amounts due in California, concluded newly established investigations of behavior in the Western markets, or ruled upon the requests for rehearing in the Pacific Northwest cases, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or liquidity.

SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the CAISO. PG&E filed for bankruptcy protection in 2001.

California Energy Market Litigation 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. State of California v. British Columbia Power Exchange et al., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are “found to exceed just and reasonable levels.” This complaint has been dismissed by the FERC and the State of California is now appealing the matter to the Ninth Circuit Court of Appeals. In addition, the State of California and others have filed various claims, which have now been consolidated, against several power suppliers to California alleging antitrust violations. Wholesale Electricity Antitrust Cases I and II, Superior Court in and for the County of San Diego, Proceedings Nos. 4204-00005 and 4204-00006. Two of the suppliers who were named as defendants in those matters, Reliant Energy Services, Inc. (and other Reliant entities) and Duke Energy and Trading, LLP (and other Duke entities), filed cross-claims against various other participants in the PX and CAISO markets, including us, attempting to expand those matters to such other participants. We have not yet filed a responsive pleading in the matter, but we believe the claims by Reliant and Duke as they relate to us are without merit.

We were also named in a lawsuit regarding wholesale contracts in California. James Millar, et al. v. Allegheny Energy Supply, et al., United States District Court in and for the District of Northern California, Case No. C02-2855 EMC. The complaint alleges basically that the contracts entered into were the result of an unfair and unreasonable market. The PX has filed a lawsuit against the State of California regarding the seizure of forward contracts and the State has filed a cross complaint against us and numerous other PX participants. Cal PX v. The State of California Superior Court in and for the County of Sacramento, JCCP No. 4203. Various preliminary motions are being filed and we cannot currently predict the outcome of this matter. The “United States Justice Foundation” is suing numerous wholesale energy contract suppliers to California, including Pinnacle West, as well as the California Department of Water Resources, based upon an alleged conflict of interest arising from the activities of a consultant for Edison International who also negotiated long-term contracts for the California Department of Water Resources. McClintock, et al. v. Yudhraja, Superior Court in and for the County of Los Angeles, Case No. GC 029447. The California Attorney General has indicated that an investigation by his office did not find evidence of improper conduct by the consultant. We believe the claims against Pinnacle West and us in the lawsuits mentioned in this paragraph are without merit and will have no material adverse impact on our financial position, results of operations or liquidity.

The Citizens Power Service Agreement

We have a long history of contractual relations with Citizens relating to providing electricity and ancillary services to the utility in Arizona owned by Citizens. Under the current power sale agreement, Pinnacle West provides for deliveries of electricity and ancillary services through May 31, 2008. On August 11, 2003, Citizens sold its Arizona utility to a subsidiary of UniSource, UNS Electric, Inc. (“UNS Electric”). In connection with that sale, the above referenced power sale agreement was amended and assigned to UNS Electric. The Company does not expect any potential claims relating to the agreement and/or any prior related agreements, including as to any claims previously raised by Citizens, to have a material adverse impact on its financial statements.

Natural Gas Supply

We and Pinnacle West Energy purchase the majority of our natural gas requirements for our gas-fired plants under contracts with a number of natural gas suppliers. Pinnacle West Energy’s and our natural gas supply is transported pursuant to a firm, full requirements transportation service agreement with El Paso Natural Gas Company. The transportation agreement features a 10-year rate moratorium established in a comprehensive rate case settlement entered into in 1996.

On July 9, 2003 the FERC issued an order that alters the existing contractual obligations and the rights of parties to the 1996 settlement. Most importantly, the July 9 order requires the conversion of all firm, full requirements contracts to contract demand contracts effective September 1, 2003. This conversion will impact all full requirements contract holders by placing additional limitations on their ability to nominate firm transportation capacity. In order for us to meet our natural gas supply and capacity requirements, we must make market purchases, which we expect to increase costs by approximately $4 million per year for natural gas supply and by approximately $9 million per year for capacity, both of which amounts are reflected in the Company’s budgets. We and Pinnacle West Energy have sought appellate review of the FERC's July 9 order

on the grounds that the FERC decision to abrogate the full requirements contracts is arbitrary and capricious and is not supported by substantial evidence. Arizona Public Service Company and Pinnacle West Energy Corporation v. Federal Energy Regulatory Commission, United States Court of Appeals for the District of Columbia, No. 03-1206. This petition for review was consolidated with a petition filed by the ACC and other full requirements contract holders. We are continuing to analyze the market to determine the most favorable source and method of meeting our natural gas requirements.

13. Asset Retirement Obligations

On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. The standard requires that these liabilities be recognized at fair value as incurred and capitalized as part of the related tangible long-lived assets. Accretion of the liability due to the passage of time is an operating expense and the capitalized cost is depreciated over the useful life of the long-lived asset. Prior to January 1, 2003 we accrued asset retirement obligations over the life of the related asset through depreciation expense.

We have asset retirement obligations for our Palo Verde nuclear facilities and certain other generation, transmission and distribution assets. The Palo Verde asset retirement obligation primarily relates to final plant decommissioning. This obligation is based on the NRC’s requirements for disposal of radiated property or plant and agreements we reached with the ACC for final decommissioning of the plant. The non-nuclear generation asset retirement obligations primarily relate to requirements for removing portions of those plants at the end of the plant life or lease term. Some of our transmission and distribution assets have asset retirement obligations because they are subject to right of way and easement agreements that require final removal. These agreements have a history of uninterrupted renewal that we expect will continue for the foreseeable future. As a result, we cannot reasonably estimate the fair value of the asset retirement obligation related to such distribution and transmission assets.

On January 1, 2003, we recorded a liability of $219 million for our asset retirement obligations, including the accretion impacts; a $67 million increase in the carrying amount of the associated assets; and a net reduction of $192 million in accumulated depreciation related primarily to the reversal of previously recorded accumulated decommissioning and other removal costs related to these obligations. Additionally, we recorded a net regulatory liability of $40 million for the asset retirement obligations related to our regulated assets. This regulatory liability represents the difference between the amount currently being recovered in regulated rates and the amount calculated under SFAS No. 143. We believe we can recover in regulated rates the transition costs and ongoing current period costs calculated in accordance with SFAS No. 143. The adoption of SFAS No. 143 did not have a material impact on our net income for the quarters ended March 31, 2003 and June 30, 2003.

In accordance with SFAS No. 71, we will continue to accrue for removal costs for our regulated assets, even if there is no legal obligation for removal. At June 30, 2003, accumulated depreciation shown on our Condensed Balance Sheets included approximately $379 million of estimated future removal costs that are not considered legal obligations.

The following schedule shows the change in our asset retirement obligations during the six-month period ended June 30, 2003 (dollars in millions):

Balance at January 1, 2003	$	219
Changes attributable to:
Liabilities incurred	—
Liabilities settled	—
Accretion expense	8
Estimated cash flow revisions	—
Balance at June 30, 2003	$	227

The following schedule shows the change in our pro forma liability for the years ended December 31, 2002 and 2001, as if we had recorded an asset retirement obligation based on the guidance in SFAS No. 143 (dollars in millions):

	2002		2001
Balance at beginning of year	$	204	$	190
Accretion expense	15		14
Balance at end of year	$	219	$	204

The pro forma effects on net income for 2002 and 2001 are immaterial.

To fund the costs we expect to incur to decommission the plant, we established external decommissioning trusts in accordance with NRC regulations. We invest the trust funds primarily in fixed income securities and domestic stock and classify them as available for sale. The following table shows the cost and fair value of our nuclear decommissioning trust fund assets which are reported in investments and other assets on the Condensed Balance Sheets at June 30, 2003 and December 31, 2002 (dollars in millions):

	June 30, 2003		December 31, 2002
Trust fund assets — at cost
Fixed income securities	$	116	$	113
Domestic stock	73		68
Total	$	189	$	181

Trust fund assets — at fair value
Fixed income securities	$	117	$	117
Domestic stock	89		77
Total	$	206	$	194

14. Intangible Assets

The Company’s gross intangible assets (which are primarily software) were $221 million at June 30, 2003 and $193 million at December 31, 2002. The increase in gross intangible assets is primarily new software. The related accumulated amortization was $113 million at June 30, 2003 and $100 million at December 31, 2002.

Amortization expense for the three months ended June 30 was $6 million in 2003 and $5 million in 2002. Amortization expense for the six months ended June 30 was $13 million in 2003 and $9 million in 2002. Amortization expense for the twelve months ended June 30 was $22 million in 2003 and $20 million in 2002. Estimated amortization expense on existing intangible assets over the next five years is $24 million in 2003, $23 million in 2004, $22 million in 2005, $20 million in 2006 and $14 million in 2007.

15. Stock-Based Compensation

In 2002, we began applying the fair value method of accounting for stock-based compensation, as provided for in SFAS No. 123, “Accounting for Stock-Based Compensation.” In accordance with the transition requirements of SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure,” we applied the fair value method prospectively, beginning with 2002 stock grants. In prior years, we recognized stock compensation expense based on the intrinsic value method allowed in Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees.”

The following chart compares our net income and stock compensation expense to what those items would have been if we had recorded stock compensation expense based on the fair value method for all stock grants through June 30, 2003 (dollars in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,				Twelve Months Ended June 30,
	2003		2002		2003		2002		2003		2002
Net Income:
As reported	$	43,175	$	64,439	$	59,108	$	96,202	$	162,249	$	230,199
Pro forma (fair value method)	42,995		64,183		58,742		95,689		161,433		228,896
Stock compensation expense (net of tax):
As reported	232		—		328		—		528		—
Pro forma (fair value method)	180		256		366		513		816		1,303

16. Other Income and Other Expense

The following table provides detail of other income and other expense for the three, six and twelve months ended June 30, 2003 and 2002 (dollars in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,						Twelve Months Ended June 30,
	2003			2002			2003			2002			2003			2002
Other income:
Environmental insurance recovery	$	—		$	—		$	—		$	—		$	—		$	1,402
Investment gains — net	—			—			578			1,565			—			633
Interest income	3,210			481			3,644			1,426			5,673			4,727
Miscellaneous	152			448			603			868			1,430			3,098
Total other income	$	3,362		$	929		$	4,825		$	3,859		$	7,103		$	9,860

Other expense:
Investment losses — net	$	(326	)	$	(222	)	$	—		$	—		$	(2,118	)	$	—
Non-operating costs (a)	(2,970		)	(4,567		)	(5,577		)	(6,874		)	(13,439		)	(15,653		)
Miscellaneous	(447		)	(841		)	(682		)	(2,345		)	(1,809		)	(3,715		)
Total other expense	$	(3,743	)	$	(5,630	)	$	(6,259	)	$	(9,219	)	$	(17,366	)	$	(19,368	)

(a) As defined by the FERC, includes below-the-line non-operating utility costs (primarily community relations and environmental compliance).

17. Guarantees

On January 1, 2003 we adopted FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under certain guarantees. It also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The disclosure provisions are effective for the year ended December 31, 2002. The initial recognition and measurement provisions of FIN No. 45 are effective on a prospective basis to guarantees issued or modified after December 31, 2002. We had no guarantees outstanding at June 30, 2003.

We have entered into various agreements that require letters of credit for financial assurance purposes. At June 30, 2003, 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. These letters of credit have expiration dates in 2003. We have also entered into approximately $113 million of letters of credit to support certain equity lessors in the Palo Verde sale-leaseback transactions. These letters of credit expire in 2005. Additionally, we have approximately $5 million of letters of credit related to counterparty collateral requirements expiring in 2003. 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.

In conjunction with our financing agreements, including our sale-leaseback transactions, we generally provide indemnifications relating to liabilities arising from or related to the agreements, except with certain limited exceptions depending on the particular agreement. We have also provided indemnifications to 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 and therefore, the overall maximum amount of the obligation under such indemnifications 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 indemnifications is likely and therefore no related liability has been recorded.

18. Related Party Transactions

During 2001, we transferred most of our marketing and trading activities to Pinnacle West. In the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts will remain at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy (see Note 5). From time to time, we enter into transactions with Pinnacle West or Pinnacle West’s subsidiaries. The following table summarizes the amounts included in the Condensed Statements of Income and Condensed Balance Sheets related to transactions with affiliated companies (dollars in millions):

	Three Months Ended June 30,				Six Months Ended June 30,				Twelve Months Ended June 30,
	2003		2002		2003		2002		2003		2002
Electric operating revenues:
Pinnacle West — marketing and trading	$	2	$	30	$	3	$	47	$	41	$	97
APS Energy Services	5		—		6		—		6		10
Total	$	7	$	30	$	9	$	47	$	47	$	107

Purchased power and fuel costs:
Pinnacle West — marketing and trading	$	—	$	—	$	—	$	6	$	129	$	30
Pinnacle West Energy	25		—		39		—		39		14
APS Energy Services	5		—		6		—		6		—
Total	$	30	$	—	$	45	$	6	$	174	$	44

	As of June 30, 2003				As of December 31, 2002
Net intercompany receivables/(payables):
Pinnacle West Energy (a)	$	460			$	(1		)
Pinnacle West — marketing and trading	23				135
Pinnacle West	(14			)	(1			)
Total	$		469		$		133

(a) The net intercompany receivable as of June 30, 2003 related to Pinnacle West Energy primarily consists of the $500 million of debt we issued to Pinnacle West Energy pursuant to the Financing Order. (See “ACC Financing Orders” in Note 5.)

Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. Intercompany receivables primarily include the loan to Pinnacle West Energy (see Note 5), the amounts related to the transfer of marketing and trading activities discussed above and intercompany sales of electricity. Intercompany payables primarily include amounts related to the purchase of electricity. Intercompany receivables and payables are generally settled on a current basis in cash.

ARIZONA PUBLIC SERVICE COMPANY

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Introduction

In this Item, we explain the results of operations, general financial condition and outlook including:

• the changes in our earnings for the three, six and twelve months ended June 30, 2003 and 2002;

• our capital needs, liquidity and capital resources;

• our business outlook and major factors that affect our financial outlook (see Note 5 and “Business Outlook” below); and

• our management of market risks.

We suggest this section be read along with the 2002 10-K and the March 2003 10-Q. Throughout this Item, we refer to specific “Notes” in the Notes to Condensed Financial Statements in this report. These Notes add further details to the discussion.

Overview of Our Business

We are an electric utility that provides either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. Electricity is delivered through a distribution system that we own. We also generate, sell and deliver electricity to wholesale customers in the western United States. Our marketing and trading division sells, in the wholesale market, our and Pinnacle West Energy’s generation output that is not needed for our Native Load, which includes loads for retail customers and traditional cost-of-service wholesale customers. In early 2003, the marketing and trading division was moved from Pinnacle West to us for future marketing and trading activities (existing wholesale contracts remain at Pinnacle West) as a result of the ACC’s Track A Order prohibiting the previously required transfer of our generating assets to Pinnacle West Energy. We do not distribute any products. Pinnacle West owns all of our outstanding common stock.

Business Segments

We have two principal business segments (determined by services and the regulatory environment):

• our regulated electricity segment, which consists of regulated traditional retail and wholesale electricity businesses and related activities and includes electricity generation, transmission and distribution; and

• our marketing and trading segment, which consists of our competitive energy business activities, including wholesale marketing and trading. During 2001, we transferred most of our marketing and trading activities to Pinnacle West. Thus, we did not have any significant marketing and trading activity in 2002. Conversely, in the first quarter of 2003, Pinnacle West moved the marketing and trading division back to us for future marketing and trading activities (existing wholesale contracts remain at Pinnacle West).

The following tables summarize net income by business segment for the three, six and twelve months ended June 30, 2003 and the comparable prior periods (dollars in millions):

	Three Months Ended June 30,				Six Months Ended June 30,				Twelve Months Ended June 30,
	2003		2002		2003		2002		2003		2002

Regulated electricity (a)	$	41	$	64	$	53	$	96	$	156	$	218
Marketing and trading	2		—		6		—		6		24
Income before accounting change	43		64		59		96		162		242
Cumulative effect of a change in accounting — net of tax (b)	—		—		—		—		—		(12		)
Net income	$	43	$	64	$	59	$	96	$	162	$	230

(a) Consistent with our October 2001 ACC filing, we entered into contracts with our affiliates to buy power through June 2003. The contracts reflect a price based on the fully-dispatchable dedication of the Pinnacle West Energy generating assets to our Native Load customers (customers receiving power under traditional cost-based rate regulation). Beginning July 1, 2003, under the ACC Track B order, we were required to solicit bids for certain estimated capacity and energy requirements. Pinnacle West Energy bid on and entered into a contract to supply most of these purchase power requirements in summer months through September 2006. See “Track B Order” in Note 5 for more information.

(b) We recorded a $12 million after tax charge in July 2001 for the cumulative effect of a change in accounting for derivatives related to the adoption of SFAS No. 133.

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 and our marketing and trading segment, gross margin refers to electric operating revenues less purchased power and fuel costs.

Operating Results — Three-month period ended June 30, 2003 compared with three-month period ended June 30, 2002

Our net income for the three months ended June 30, 2003 was $43 million compared with $64 million for the prior year. The period-to-period decrease of $21 million was primarily due to (amounts after tax):

• $23 million of higher purchased power and fuel costs primarily due to higher hedged gas and power prices;

• $5 million of higher operating costs primarily related to higher pension and other benefit costs;

• a $4 million earnings decrease due to a retail electricity price reduction; and

• $3 million of higher depreciation expense primarily related to increased plant assets in service.

The above decreases were partially offset by (amounts after tax):

• $8 million of higher retail sales primarily due to customer growth, excluding weather effects;

• $4 million of lower regulatory asset amortization; and

• $2 million of other miscellaneous factors, net.

For additional details, see the following discussion.

The major factors that increased (decreased) net income were as follows (dollars in millions):

	Increase (Decrease)
Regulated electricity segment gross margin:
Increased purchased power and fuel costs primarily due to higher hedged gas and power prices	$	(38	)
Retail electricity price reduction effective July 1, 2002	(7		)
Higher retail sales primarily due to customer growth, excluding weather effects	14
Effects of weather on retail sales	(1		)
Miscellaneous factors, net	(3		)
Net decrease in regulated electricity segment gross margin	(35		)
Marketing and trading segment gross margin:
Increase in marketing and trading segment gross margin resulting primarily from the transfer of the marketing and trading activities (see Note 18)	4
Net increase in marketing and trading segment gross margin	4
Net decrease in regulated electricity and marketing and trading segments’ gross margins	(31		)
Higher operations and maintenance expense primarily related to increased pension and other benefit costs	(8		)
Higher net interest expense primarily due to higher debt balances	(3		)
Lower depreciation and amortization primarily related to lower regulatory asset amortization partially offset by increased plant assets	3
Higher other income primarily related to interest income from loan to Pinnacle West Energy (see Notes 4 and 5)	2
Lower other expense due to lower losses on disposition of property	2
Miscellaneous factors, net	1
Net decrease in income before income taxes	(34		)
Lower income taxes primarily due to lower income	13
Net decrease in net income	$	(21	)

Regulated Electricity Segment Gross Margin

Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $5 million higher in the three months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $3 million increase in revenues related to traditional wholesale sales as a result of higher prices;

• an $8 million decrease in revenues related to retail load hedge management wholesale sales primarily as a result of lower sales volumes;

• a $7 million decrease in retail revenues related to a reduction in retail electricity prices;

• a $20 million increase in retail revenues related to customer growth, excluding weather effects;

• a $2 million decrease in retail revenues related to weather; and

• a $1 million net decrease in other miscellaneous factors.

Regulated electricity segment purchased power and fuel costs were $40 million higher in the three months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $3 million increase in costs related to traditional wholesale sales as a result of higher prices;

• a $30 million increase in purchased power and fuel costs due to higher hedged gas and power prices;

• a $6 million increase related to customer growth, excluding weather effects;

• a $1 million decrease related to the effects of weather on retail sales; and

• a $2 million increase due to other miscellaneous factors.

Marketing and Trading Segment Gross Margin

Marketing and trading segment revenues were $106 million higher in the three months ended June 30, 2003, compared with the same period in the prior year as a result of:

• $88 million of higher marketing and trading revenues as a result of the transfer of marketing and trading activities; and

• an $18 million increase in revenues from generation sales other than Native Load primarily due to higher sales volumes and higher prices.

Marketing and trading segment purchased power and fuel costs were $102 million higher in the three months ended June 30, 2003, compared to the same period in the prior year as a result of:

• $84 million of higher marketing and trading purchased power and fuel costs as a result of the transfer of marketing and trading activities; and

• an $18 million increase in fuel costs related to generation sales other than Native Load primarily because of higher natural gas prices and higher sales volumes.

Operating Results — Six-month period ended June 30, 2003 compared with six-month period ended June 30, 2002

Our net income for the six months ended June 30, 2003 was $59 million compared with $96 million for the prior year. The period-to-period decrease of $37 million was primarily due to (amounts after tax):

• $31 million of higher purchased power and fuel costs primarily due to higher hedged gas and power prices;

• a $7 million earnings decrease due to a retail electricity price reduction;

• $6 million of higher operating costs related to higher pension and other benefit costs;

• $6 million of higher operating costs primarily related to increased customer service costs;

• $5 million of higher depreciation expense related to increased plant assets in service;

• $4 million from the effects of weather on retail sales; and

• $4 million of miscellaneous factors, net.

The above decreases were partially offset by (amounts after tax):

• $13 million of higher retail sales primarily due to customer growth, excluding weather effects;

• $8 million of lower regulatory asset amortization; and

• $5 million of higher earnings contributions from our marketing and trading activities primarily due to the transfer of marketing and trading activities.

For additional details, see the following discussion.

The major factors that increased (decreased) net income were as follows (dollars in millions):

	Increase (Decrease)
Regulated electricity segment gross margin:
Increased purchased power and fuel costs due to higher hedged gas and power prices	$	(52	)
Retail electricity price reduction effective July 1, 2002	(12		)
Effects of milder weather on retail sales	(7		)
Higher retail sales volumes due to customer growth, excluding weather effects	21
Miscellaneous factors, net	(3		)
Net decrease in regulated electricity segment gross margin	(53		)
Marketing and trading segment gross margin:
Increase in generation sales other than Native Load due to higher sales volumes	7
Increase in marketing and trading segment gross margin resulting from the transfer of the marketing and trading activities (see Note 18)	2
Net increase in marketing and trading segment gross margin	9
Net decrease in regulated electricity and marketing and trading segments’ gross margins	(44		)
Higher operations and maintenance expense primarily related to increased pension and other benefit costs and increased customer service costs	(20		)
Higher interest expense due to higher debt balances	(4		)
Lower depreciation and amortization primarily related to lower regulatory asset amortization partially offset by increased plant assets	5
Miscellaneous factors, net	2
Net decrease in income before income taxes	(61		)
Lower income taxes primarily due to lower income	24
Net decrease in net income	$	(37	)

Regulated Electricity Segment Gross Margin

Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $8 million higher in the six months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $4 million increase related to traditional wholesale sales as a result of higher sales volumes and higher prices;

• an $8 million decrease in revenues related to retail load hedge management wholesale sales;

• a $12 million decrease in retail revenues related to a reduction in retail electricity prices;

• a $13 million decrease in retail revenues related to milder weather;

• a $34 million increase in retail revenues related to customer growth, excluding weather effects; and

• a $3 million net increase due to other miscellaneous factors.

Regulated electricity segment purchased power and fuel costs were $61 million higher in the six months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $4 million increase related to traditional wholesale sales as a result of higher sales volumes and higher prices;

• a $44 million increase in purchased power and fuel costs due to higher gas and power prices;

• a $6 million decrease related to the effects of milder weather on retail sales;

• a $13 million increase related to customer growth, excluding weather effects; and

• a $6 million net increase due to other miscellaneous factors.

Marketing and Trading Segment Gross Margin

Marketing and trading segment revenues were $186 million higher in the six months ended June 30, 2003, compared with the same period in the prior year as a result of:

• a $55 million increase from generation sales other than Native Load primarily due to higher prices and higher sales volumes; and

• $131 million of higher marketing and trading revenues as a result of the transfer of marketing and trading activities.

Marketing and trading segment purchased power and fuel costs were $177 million higher in the six months ended June 30, 2003, compared to the same period in the prior year as a result of:

• a $48 million increase in fuel costs related to generation sales other than Native Load primarily because of higher natural gas prices and higher sales volumes; and

• $129 million of higher marketing and trading purchased power and fuel costs as a result of the transfer of marketing and trading activities.

Operating Results — Twelve-month period ended June 30, 2003 compared with twelve-month period ended June 30, 2002

Our net income for the twelve months ended June 30, 2003 was $162 million compared with $230 million for the prior year. The period-to-period decrease of $68 million was primarily due to (amounts after tax):

• $50 million of higher purchased power and fuel prices primarily due to higher hedged gas and power prices;

• $23 million of higher operations and maintenance expenses primarily related to 2002 severance costs;

• $19 million of lower earnings contributions from our marketing and trading activities primarily related to lower realized wholesale margins due to lower unit margins partially offset by higher volumes;

• a $16 million earnings decrease due to two retail electricity price reductions;

• $14 million from the effects of milder weather on retail sales;

• $9 million of higher pension and other benefit costs;

• $9 million of higher depreciation expense related to increased plant assets in service;

• $4 million of higher net interest expense related to higher debt balances; and

• $2 million of miscellaneous factors, net.

The above decreases were partially offset by (amounts after tax):

• $26 million of higher retail sales primarily due to customer growth, excluding weather effects;

• $17 million of lower regulatory asset amortization;

• $14 million of lower purchased power and fuel costs related to the 2001 reliability program (the addition of generating capability to enhance reliability for the summer of 2001);

• a $12 million charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133, recorded in the twelve months ended June 30, 2002;

• $8 million of 2001 charges related to Enron and its affiliates; and

• a $1 million increase from generation sales other than Native Load primarily due to higher prices and sales volumes.

For additional details, see the following discussion.

The major factors that increased (decreased) net income were as follows (dollars in millions):

	Increase (Decrease)
Regulated electricity segment gross margin:
Increased purchased power and fuel costs due to higher hedged gas and power prices	$	(84	)
Retail electricity price reductions effective July 1, 2001 and July 1, 2002	(27		)
Effects of milder weather on retail sales	(23		)
Higher retail sales volumes due to customer growth, excluding weather effects	44
2001 charges related to purchase power contracts with Enron	13
Lower purchased power and fuel costs related to the 2001 reliability program	23
Miscellaneous factors, net	1
Net decrease in regulated electricity segment gross margin	(53		)
Marketing and trading segment gross margin:
Lower realized wholesale margins due to lower unit margins, partially offset by higher volumes	(32		)
Increase in generation sales other than Native Load primarily due to higher sales volumes	2
Net decrease in marketing and trading segment gross margin	(30		)
Net decrease in regulated electricity and marketing and trading segments’ gross margins	(83		)
Higher operations and maintenance expense related primarily to 2002 severance costs of approximately $34 million and increased pension and other benefit costs	(54		)
Higher net interest expense primarily due to higher debt balances and lower capitalized interest	(7		)
Lower depreciation and amortization primarily related to lower regulatory asset amortization partially offset by increased plant assets	14
Higher taxes other than income taxes due to increased property taxes on higher property balances	(5		)
Net decrease in income from continuing operations before income taxes	(135		)
Lower income taxes primarily due to lower income	55
Increase due to cumulative effect of a change in accounting for derivatives — net of income tax	12
Net decrease in net income	$	(68	)

Regulated Electricity Segment Gross Margin

Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $234 million lower in the twelve months ended June 30, 2003, compared with the same period in the prior year as a result of:

• an $18 million increase related to traditional wholesale sales as a result of higher prices and higher sales volumes;

• a $263 million decrease related to retail load hedge management wholesale sales primarily as a result of lower prices and lower sales volumes;

• a $27 million decrease in retail revenues related to reductions in retail electricity prices;

• a $37 million decrease in retail revenues related to milder weather;

• a $63 million increase in retail revenues related to customer growth and higher average usage, excluding weather effects; and

• a $12 million net increase due to other miscellaneous factors.

Regulated electricity segment purchased power and fuel costs were $181 million lower in the twelve months ended June 30, 2003, compared with the same period in the prior year as a result of:

• an $18 million increase related to traditional wholesale sales as a result of higher prices and higher sales volumes;

• a $237 million decrease related to retail load hedge management wholesale sales primarily as a result of lower prices and lower sales volumes;

• a $58 million increase in purchased power and fuel costs due to higher hedged gas and power prices;

• a $14 million decrease related to the effects of milder weather on retail sales;

• a $19 million increase related to customer growth, excluding weather effects;

• a $13 million net decrease for charges in 2001 related to purchased power contracts with Enron and its affiliates;

• $23 million of lower purchased power costs related to the 2001 generation reliability program; and

• an $11 million net increase due to other miscellaneous factors.

Marketing and Trading Segment Gross Margin

Marketing and trading segment revenues were $136 million higher in the twelve months ended June 30, 2003, compared with the same period in the prior year as a result of:

• $78 million of higher realized wholesale revenues primarily due to higher volumes; and

• a $58 million increase from generation sales other than Native Load primarily due to higher sales volumes and higher prices.

Marketing and trading segment purchased power and fuel costs were $166 million higher in the twelve months ended June 30, 2003, compared to the same period in the prior year as a result of:

• $110 million of increased purchased power costs related to other realized marketing and trading activities primarily due to higher volumes; and

• $56 million of increased fuel costs related to generation sales other than Native Load primarily because of higher sales volumes and higher natural gas prices.

Liquidity and Capital Resources

Capital Expenditure Requirements

The following table summarizes the actual capital expenditures for the six months ended June 30, 2003 and estimated capital expenditures for the next three years (dollars in millions):

	Actual		Estimated
	Six Months Ended June 30,		Twelve Months Ended December 31,
	2003		2003		2004		2005
Delivery	$	143	$	273	$	289	$	354
Generation (a)	62		123		108		169
Other	3		5		2		2
Total	$	208	$	401	$	399	$	525

(a) As discussed in Note 5 under “General Rate Case and Retail Rate Adjustment Mechanisms,” as part of our 2003 general rate case, we requested rate base treatment of the PWEC Dedicated Assets.

Delivery capital expenditures are comprised of T&D infrastructure additions and upgrades, capital replacements, new customer construction and related information systems and facility costs. Examples of the types of projects included in the forecast include T&D lines and substations, line extensions to new residential and commercial developments and upgrades to customer information systems. In addition, we began

several major transmission projects in 2001, with additional major projects scheduled to begin over the next several years. These projects are periodic in nature and are driven by strong regional customer growth. We expect to spend about $100 million on major transmission projects during the 2003 to 2005 time frame, and these amounts are included in “Delivery” in the table above.

Generation capital expenditures are comprised of various improvements for our existing fossil and nuclear plants and the replacement of Palo Verde steam generators. 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. Generation also contains nuclear fuel expenditures of approximately $30 million annually for 2003 to 2005.

Replacement of the steam generators in Palo Verde Unit 2 is presently scheduled for completion during the fall outage of 2003. The Palo Verde owners have approved the manufacture of two additional sets of steam generators. We expect that these generators will be installed in Units 1 and 3 in the 2005 to 2007 time frame. Our portion of steam generator expenditures for Units 1, 2 and 3 is approximately $155 million, which will be spent from 2003 through 2008. In 2003 through 2005, $106 million of the costs are included in the generation capital expenditures table above and would be funded with internally-generated cash or external financings.

Capital Resources and Cash Requirements

Contractual Obligations The following table summarizes actual contractual requirements for the six months ended June 30, 2003 and estimated contractual commitments for the next five years and thereafter (dollars in millions):

	Actual		Estimated
	Six Months Ended		Twelve Months Ended December 31,
	June 30 2003		2003		2004		2005		2006		2007		There-after
Long-term debt payments	$	33	$	87	$	205	$	400	$	84	$	—	$	1,931
Capital lease payments	1		4		3		3		3		2		5
Operating lease payments	40		60		60		60		59		59		456
Purchase power and fuel commitments	87		209		88		28		31		17		162
Total contractual commitments	$	161	$	360	$	356	$	491	$	177	$	78	$	2,554

Off-Balance Sheet Arrangements

returns or both. A VIE is a corporation, partnership, trust or any other legal structure that either does not have equity investors with voting rights or has equity investors that do not provide sufficient financial resources for the entity to support its activities. FIN No. 46 is effective immediately for any VIE created after January 31, 2003 and is effective July 1, 2003 for VIEs created before February 1, 2003. We currently do not expect FIN No. 46 to have a material impact on our financial statements.

In 1986, we entered into agreements with three separate SPE 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. While we continue to evaluate the guidance, we currently do not expect that we will be required to consolidate the Palo Verde SPEs under FIN No. 46.

We are exposed to losses under the Palo Verde sale-leaseback agreements upon the occurrence of certain events that we do 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), we would be required to assume the debt associated with the transactions, make specified payments to the equity participants and take title to the leased Unit 2 interests, which, if appropriate, may be required to be written down in value. If such an event had occurred as of June 30, 2003, we would have been required to assume approximately $268 million of debt and pay the equity participants approximately $200 million.

Credit Ratings

The ratings of our securities as of August 13, 2003 are shown below and are considered to be “investment-grade” ratings. The ratings reflect the respective views of the rating agencies, from which an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely affect the market price of our securities and serve to increase our cost of and access to capital.

	Moody’s	Standard & Poor’s
Senior secured	A3	A-
Senior unsecured	Baa1	BBB
Secured lease obligation bonds	Baa2	BBB
Commercial paper	P-2	A-2

Outlook	Stable	Stable

Debt Provisions

Our significant debt covenants related to our financing arrangements include a debt-to-total-capitalization ratio and an interest coverage test (as defined in the agreements). We are in compliance with such covenants and anticipate that we will continue to meet all the significant covenant requirement levels. The ratio of debt to total capitalization cannot

exceed 65%. At June 30, 2003, our ratio was approximately 54%. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements. The coverage is approximately 4 times for our bank agreements and 13 times for our mortgage indenture. 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.

Our financing agreements do not contain “ratings triggers” that would result in an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a ratings downgrade, we may be subject to increased interest costs under certain financing agreements.

All of our bank agreements contain cross-default provisions that would result in defaults and the potential acceleration of payment under these bank agreements if we were to default under other agreements. Our credit agreements generally contain provisions under which the lenders could refuse to advance loans in the event of a material adverse change in our financial condition or financial prospects.

Capital Requirements and Resources

Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. See “Business Outlook - Regulatory Matters” below and Notes 4 and 5 for discussion of the $500 million financing arrangement between Pinnacle West Energy and us authorized by the ACC pursuant to the Financing Order and our related issuance of $500 million of debt. See below and Note 5 for discussion of a $125 million interim financing arrangement between Pinnacle West and us.

On November 22, 2002, the ACC issued the Interim Financing Order, which permits us to (a) make short-term advances to Pinnacle West in the form of an inter-affiliate line of credit in the amount of $125 million, or (b) guarantee $125 million of Pinnacle West’s short-term debt, subject to certain conditions. As of June 30, 2003, there were no borrowings outstanding under this financing arrangement.

We pay for our capital requirements with cash from operations and, to the extent necessary, external financings. We have historically paid for our dividends to Pinnacle West with cash from operations. As discussed in Note 5, we must maintain a common equity ratio of at least 40% and may not pay common dividends if the payment would reduce our common equity below that threshold. As defined in the Financing Order, common equity ratio is common equity divided by common equity plus long-term debt, including current maturities of long-term debt. At June 30, 2003, our common equity ratio was approximately 45%.

On April 7, 2003, we redeemed approximately $33 million of our First Mortgage Bonds, 8% Series due 2025, and on August 1, 2003, we redeemed approximately $54 million of our First Mortgage Bonds, 7.25% Series due 2023.

Although provisions in our first mortgage bond indenture, articles of incorporation and ACC financing orders establish maximum amounts of additional first mortgage bonds, debt and preferred stock that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements.

We are part of a multi-employer pension plan sponsored by Pinnacle West. Pinnacle West contributes at least the minimum amount required under IRS regulations, but no more than the maximum tax-deductible amount. The minimum required funding takes into consideration the value of the fund assets and our pension obligation. Pinnacle West elected to contribute cash to our pension plan in each of the last five years; the minimum required contributions during each of those years was zero. Specifically, Pinnacle West contributed $73 million for 2002 ($46 million of which was contributed in June 2003), $24 million for 2001, $44 million for 2000 ($20 million of which was contributed in 2001), $25 million for 1999 and $14 million for 1998. We fund our share of the pension contribution. We represent approximately 90% of the total funding amounts described above. The assets in the plan are mostly domestic common stocks, bonds and real estate. Future year contribution amounts are dependent on fund performance and fund valuation assumptions.

Critical Accounting Policies

In preparing the financial statements in accordance with GAAP, management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the impacts of regulatory accounting and the determination of the appropriate accounting for our pension and other postretirement benefits, derivatives and mark-to-market accounting. There have been no changes to our critical accounting policies since our 2002 10-K except for the discussion related to SFAS No. 143 (see Note 13). See “Critical Accounting Policies” in Item 7 of the 2002 10-K for further details about our critical accounting policies.

Business Outlook

In this section we discuss a number of factors affecting our business outlook.

Regulatory Matters

See Note 5 for a discussion of ACC regulatory matters, including our general rate case filed on June 27, 2003.

Wholesale Power Market Conditions

The marketing and trading division focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer demand.

Pinnacle West moved this division to us in early 2003 for future marketing and trading activities (existing wholesale contracts remain at Pinnacle West) as a result of the ACC’s Track A Order prohibiting our transfer of generating assets to Pinnacle West Energy. Additionally, the marketing and trading division, subject to specified parameters, markets, hedges and trades in electricity, fuels, and emission allowances and credits. Our future earnings will be affected by the strength or weakness of the wholesale power market. The market has suffered a substantial reduction in overall liquidity because there are fewer creditworthy counterparties and because several key participants have exited the market or scaled back their activities. Based on the erosion in the market and on the market outlook for the remainder of the year, we currently believe that the contribution from our trading activities will be significantly lower in 2003 than in 2002, and will remain at about the 2003 level in 2004.

Factors Affecting Operating Revenues

General Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and from competitive retail and wholesale bulk power markets in the western United States. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer as well as electricity prices and variations in weather from period to period.

Customer Growth Customer growth in our service territory averaged about 3.6% a year for the three years 2000 through 2002; we currently expect customer growth to average about 3.5% per year from 2003 to 2005. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in 2003 through 2005, before the retail effects of weather variations. The customer and sales growth referred to in this paragraph applies to energy delivery customers. Customer growth for the six month period ended June 30, 2003 compared with the prior year period was 3.2%.

Retail Rate Changes As part of the 1999 Settlement Agreement, we agreed to a series of annual retail electricity price reductions of 1.5% on July 1 for each of the years 1999 to 2003 for a total of 7.5%. The final price reduction was implemented July 1, 2003. See “1999 Settlement Agreement” in Note 5 for further information. In addition, the Company has requested a 9.8% retail rate increase to be effective July 1, 2004. See “General Rate Case and Retail Rate Adjustment Mechanisms” in Note 5 for further information.

Other Factors Affecting Future Financial Results

Purchased Power and Fuel Costs Purchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for purchased power and generation fuel, our power plant performance, prevailing market prices and our hedging program for managing such costs. See “Natural Gas Supply” in Note 12 for more information on fuel costs.

On August 2, 2003 Unit 3 of the Cholla Power Plant tripped due to a generator failure. Based on testing and unit inspection to date, we expect the cost to repair the generator to be approximately $7 million, most of which should be covered by insurance, and expect the unit to be back in service by the end of November, 2003. We are continuing to evaluate the damage to the unit; however, we currently estimate replacement power costs to be approximately $20 million.

Operations and Maintenance Expenses Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant additions and operations, inflation, outages, higher trending pension and other postretirement benefit costs and other factors. In July 2002, we implemented a voluntary workforce reduction as

part of our cost reduction program. We recorded $34 million before taxes in voluntary severance costs in the second half of 2002.

Depreciation and Amortization Expenses Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property and changes in regulatory asset amortization. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions):

1999		2000		2001		2002		2003		2004		Total
$	164	$	158	$	145	$	115	$	86	$	18	$	686

Property Taxes Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in-service and under construction. Our average property tax rate was 9.7% of assessed value for 2002 and 9.3% for 2001. We expect property taxes to increase primarily due to our additions to existing facilities.

Interest Expense Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our capital requirements and our internally generated cash flow. Capitalized interest offsets a portion of interest expense while capital projects are under construction. We stop recording capitalized interest on a project when it is placed in commercial operation. Interest expense is also affected by interest rates on variable-rate debt and interest rates on the refinancing of the Company’s future liquidity needs.

Retail Competition The regulatory developments and legal challenges to the Rules discussed in Note 5 have raised considerable uncertainty about the status and pace of retail electric competition and of electric restructuring in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are currently no active retail competitors providing unbundled energy or other utility services to our customers. As a result, we cannot predict when, and the extent to which, additional competitors will re-enter our service territory.

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

Risk Factors

Exhibit 99.1, which is hereby incorporated by reference, contains a discussion of risk factors involving the Company.

Forward-Looking Statements

This document contains forward-looking statements based on current expectations and we assume no 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 “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 us. These factors include, but are not limited to, 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 and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including the outcome of the rate case we filed with the ACC on June 27, 2003 and the wholesale electric price mitigation plan adopted by the FERC; regional economic and market conditions, including the results of litigation and other proceedings resulting from the California energy situation, volatile purchased power and fuel costs and the completion of generation and transmission construction in the region, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital and access to capital markets; weather variations affecting local and regional customer energy usage; conservation programs; power plant performance; our ability to compete successfully outside traditional regulated markets (including the wholesale market); our ability to manage our marketing and trading activities and the use of derivative contracts in our business; technological developments in the electric industry; the performance of the stock market, which affects the amount of our required contributions to our pension plan and nuclear decommissioning trust funds; and other uncertainties, all of which are difficult to predict and many of which are beyond our control.

Item 3. Market Risks

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

Commodity Price Risk

We are exposed to the impact of market fluctuations in the commodity price and transportation costs of electricity, natural gas, coal and emissions allowances. We manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options and swaps. The ERMC, consisting of senior officers, 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 enter into derivative transactions 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.

unrealized) on energy trading contracts that qualify as derivatives are included in marketing and trading segment revenues on the Condensed Statements of Income on a net basis. Derivative instruments used for non-trading activities are accounted for in accordance with SFAS No. 133. See Note 10 for details on the change in accounting for energy trading contracts.

Both non-trading and trading derivatives are classified as assets and liabilities from risk management and trading activities in the Condensed Balance Sheets. For non-trading derivative instruments that qualify for hedge accounting treatment, changes in the fair value of the effective portion are recognized in common stock equity (as a component of accumulated other comprehensive income (loss)). Non-trading derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. Gains and losses related to non-trading derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or purchased power and fuel expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings. If it becomes probable that a forecasted transaction will not occur, we discontinue the use of hedge accounting and recognize in income the unrealized gains and losses that were previously recorded in other comprehensive income (loss). In the event a non-trading derivative is terminated or settled, the unrealized gains and losses remain in other comprehensive income (loss) and are recognized in income when the underlying transaction impacts earnings.

Derivatives associated with trading activities are adjusted to fair value through income. Derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception and are not reflected on the balance sheet at fair value. Most of our non-trading electricity purchase and sales agreements qualify as normal purchases and sales and are exempted from recognition in the financial statements until the electricity is delivered.

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

• System - non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements of our regulated electricity business segment; and

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

The following tables show the changes in mark-to-market of our system and marketing and trading derivative positions for the six months ended June 30, 2003 and 2002 (dollars in millions):

	Six Months Ended June 30, 2003						Six Months Ended June 30, 2002
	System			Marketing and Trading			System			Marketing and Trading
Mark-to-market of net positions at beginning of period	$	(50	)	$	—		$	(107	)	$	—
Change in mark-to-market gains (losses) for future period deliveries	6			(1		)	(3		)	—
Changes in cash flow hedges recorded in OCI	34			—			44			—
Ineffective portion of changes in fair value recorded in earnings	6			—			3			—
Mark-to-market losses realized during the period	7			—			6			—
Mark-to-market of net positions at end of period	$	3		$	(1	)	$	(57	)	$	—

As of June 30, 2003, a hypothetical adverse price movement of 10% in the market price of our risk management and trading assets and liabilities would have decreased the fair market value of these contracts by approximately $21 million, compared to a $16 million decrease that would have been realized as of June 30, 2002. A hypothetical favorable price movement of 10% would have increased the fair market value of these contracts by approximately $22 million, compared to an $18 million increase that would have been realized as of June 30, 2002. 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 and Counterparty Risk

We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure related to our counterparties. Despite the fact that the great majority of trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on earnings for a given period. Counterparties in the portfolio consist principally of 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. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. We also enter into credit default swap instruments to limit our credit risk related to certain counterparties. Valuation adjustments are established representing our estimated credit losses on our

overall exposure to counterparties. See “Critical Accounting Policies - Mark-to-Market Accounting” in Item 7 of our 2002 10-K for more discussion on our valuation methods.

Item 4. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures

The Company’s management, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures as of the end of the period covered by this report have been designed and are functioning effectively to provide reasonable assurance that the information required to be disclosed by the Company in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

(b) Change in Internal Control over Financial Reporting

No change in the Company’s internal control over financial reporting occurred during the Company’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Note 12 of Notes to Condensed Financial Statements in Part 1, Item 1, of this report for a discussion of the Company’s appeal of a FERC order.

Item 5. Other Information

Construction and Financing Programs

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

Regulatory Matters

See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of regulatory developments.

Environmental Matters

Clean Air Act

As previously reported, the EPA has reviewed an “Annex” to the Visibility Commission recommendations that specify the regional sulfur dioxide emission milestones. See “Environmental Matters — Clean Air Act” in Part I, Item 1 of the 2002 10-K. The EPA approved the Annex and issued final rules implementing it in June 2003.

Water Supply

The Four Corners region, in which the Four Corners power plant is located, has been experiencing drought conditions that may affect the water supply for the plants in 2003, as well as later years if adequate moisture is not received in the watershed that supplies the area. See “Environmental Matters — Water Supply” in Item I, Part 1 of the 2002 10-K. We have entered into agreements with various parties to provide additional temporary supplies of water, if required, and are continuing to work with area stakeholders to minimize the effect, if any on operations of the plant. The effect of the drought cannot be fully assessed at this time, and we cannot predict the ultimate outcome, if any, of the drought or whether the drought will adversely affect the amount of power available, or the price thereof, from the Four Corners power plant.

Natural Gas Supply

See Note 12 of Notes to Condensed Financial Statements in Part 1, Item 1 of this report for a discussion of a recent FERC ruling.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

Exhibit No.		Description

12.1		Ratio of Earnings to Fixed Charges

31.1		Certification of Jack E. Davis, the Registrant’s principal executive officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of Donald E. Brandt, the Registrant’s principal financial officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification of Jack E. Davis, the Registrant’s principal executive officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Donald E. Brandt, the Registrant’s principal financial officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1		APS Risk Factors

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 No.	Description	Originally Filed as Exhibit:	File No.(a)	Date Effective
3.1	Articles of Incorporation restated as of May 25, 1988	4.2 to Form S-3 Registration Nos. 33910 and 33-55248 by means of September 24, 1993 Form 8-K Report	1-4473	9-29-93
3.2	Bylaws, amended as of September 18, 2002	3.2 to Pinnacle West September 2002 Form 10-Q Report	1-8962	11-14-02
10.1	Fifty-eighth Supplemental Indenture	10.1 to Pinnacle West June 2003 Form 10-Q Report	1-8962	8-14-03
10.2	Seventh Supplemental Indenture dated as of May 1, 2003	10.2 to Pinnacle West June 2003 Form 10-Q Report	1-8962	8-14-03

(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.

(b) Reports on Form 8-K

During the quarter ended June 30, 2003, and the period from May 1 through August 14, 2003, we filed the following reports on Form 8-K:

Report dated May 6, 2003 regarding the Track B Order and asset retirement obligations.

Report dated May 7, 2003 comprised of Exhibits to Registration Statement No. 333-90824 relating to the issuance of $300 million of 4.650% Notes due 2015 and $200 million of 5.625% Notes due 2033.

Report dated May 13, 2003 comprised of slides presented at Pinnacle West analyst meetings.

Report dated June 27, 2003 regarding our rate request filed with the ACC on June 27, 2003.

Report dated June 30, 2003 containing exhibits comprised of Pinnacle West financial information, earnings variance explanations and earnings news release.

SIGNATURES

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

		ARIZONA PUBLIC SERVICE COMPANY
			(Registrant)



Dated:	August 14, 2003	By:	Donald E. Brandt
			Donald E. Brandt
			Senior Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)