10-Q 1 e-9979.txt QUARTERLY REPORT FOR THE QTR ENDED 03/31/2003 Securities and Exchange Commission Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended MARCH 31, 2003 OR [ ] 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 [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] 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 May 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 ADEQ - Arizona Department of Environmental Quality ALJ - Administrative Law Judge APS - Arizona Public Service Company, the Company APS Energy Services - APS Energy Services Company, Inc., a subsidiary of Pinnacle West 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 Fitch - Fitch, Inc. GAAP - accounting principles generally accepted in the United States of America Interim Financing Order - Order issued by the ACC on November 22, 2002 relating to our request to provide financing or credit support to Pinnacle West IRS - United States Internal Revenue Service ISO - California Independent System Operator 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 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 1 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 VIE - variable interest entity 2 PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Three Months Ended March 31, ---------------------------- 2003 2002 ------------ ------------ (Dollars in Thousands) ELECTRIC OPERATING REVENUES: Regulated electricity segment $ 387,168 $ 383,741 Marketing and trading segment 91,558 10,693 ------------ ------------ Total 478,726 394,434 ------------ ------------ PURCHASED POWER AND FUEL COSTS: Regulated electricity segment 89,382 68,285 Marketing and trading segment 85,940 10,100 ------------ ------------ Total 175,322 78,385 ------------ ------------ OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS 303,404 316,049 ------------ ------------ OTHER OPERATING EXPENSES: Operations and maintenance excluding purchased power and fuel costs 121,837 109,321 Depreciation and amortization 95,557 97,622 Income taxes 10,966 21,134 Other taxes 28,214 26,751 ------------ ------------ Total 256,574 254,828 ------------ ------------ OPERATING INCOME 46,830 61,221 ------------ ------------ OTHER INCOME (DEDUCTIONS): Income taxes 504 365 Other income 1,789 3,152 Other expense (2,842) (3,811) ------------ ------------ Total (549) (294) ------------ ------------ INCOME BEFORE INTEREST DEDUCTIONS 46,281 60,927 ------------ ------------ INTEREST DEDUCTIONS: Interest on long-term debt 32,968 31,737 Interest on short-term borrowings 1,259 1,137 Debt discount, premium and expense 720 642 Capitalized interest (4,599) (4,352) ------------ ------------ Total 30,348 29,164 ------------ ------------ NET INCOME $ 15,933 $ 31,763 ============ ============
See Notes to Condensed Financial Statements. 3 ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Twelve Months Ended March 31, ---------------------------- 2003 2002 ------------ ------------ (Dollars in Thousands) ELECTRIC OPERATING REVENUES: Regulated electricity segment $ 2,062,766 $ 2,533,022 Marketing and trading segment 114,919 312,911 ------------ ------------ Total 2,177,685 2,845,933 ------------ ------------ PURCHASED POWER AND FUEL COSTS: Regulated electricity segment 616,465 1,165,846 Marketing and trading segment 108,502 178,024 ------------ ------------ Total 724,967 1,343,870 ------------ ------------ OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS 1,452,718 1,502,063 ------------ ------------ OTHER OPERATING EXPENSES: Operations and maintenance excluding purchased power and fuel costs 508,361 460,341 Depreciation and amortization 397,575 414,819 Income taxes 122,785 161,206 Other taxes 109,388 102,532 ------------ ------------ Total 1,138,109 1,138,898 ------------ ------------ OPERATING INCOME 314,609 363,165 ------------ ------------ OTHER INCOME (DEDUCTIONS): Income taxes 6,287 (351) Other income 4,669 20,844 Other expense (19,252) (18,680) ------------ ------------ Total (8,296) 1,813 ------------ ------------ INCOME BEFORE INTEREST DEDUCTIONS 306,313 364,978 ------------ ------------ INTEREST DEDUCTIONS: Interest on long-term debt 129,693 125,274 Interest on short-term borrowings 5,538 4,583 Debt discount, premium and expense 2,966 2,963 Capitalized interest (15,397) (15,687) ------------ ------------ Total 122,800 117,133 ------------ ------------ INCOME BEFORE ACCOUNTING CHANGE 183,513 247,845 Cumulative effect of change in accounting for derivatives - net of income tax benefit of $8,099 -- (12,446) ------------ ------------ NET INCOME $ 183,513 $ 235,399 ============ ============
See Notes to Condensed Financial Statements 4 ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS (Unaudited) ASSETS (Dollars in Thousands)
March 31, December 31, 2003 2002 ------------ ------------ UTILITY PLANT: Electric plant in service and held for future use $ 8,413,176 $ 8,299,131 Less accumulated depreciation and amortization 3,305,581 3,442,571 ------------ ------------ Total 5,107,595 4,856,560 Construction work in progress 362,351 329,089 Intangible assets, net of accumulated amortization 111,012 93,259 Nuclear fuel, net of accumulated amortization 12,232 7,466 ------------ ------------ Utility plant - net 5,593,190 5,286,374 ------------ ------------ INVESTMENTS AND OTHER ASSETS: Decommissioning trust accounts 204,179 194,440 Assets from risk management and trading activities - long-term 29,033 31,622 Other assets 8,865 19,964 ------------ ------------ Total investments and other assets 242,077 246,026 ------------ ------------ CURRENT ASSETS: Cash and cash equivalents 31,783 42,549 Trust fund for bond redemption 87,225 -- Accounts receivable: Service customers 159,763 136,945 Other 111,777 202,597 Allowance for doubtful accounts (1,022) (1,341) Accrued utility revenues 57,306 72,915 Materials and supplies, at average cost 78,459 79,985 Fossil fuel, at average cost 32,913 28,185 Deferred income taxes 4,094 4,094 Assets from risk management and trading activities 88,419 39,616 Other 43,941 45,361 ------------ ------------ Total current assets 694,658 650,906 ------------ ------------ DEFERRED DEBITS: Regulatory assets 219,344 241,045 Unamortized debt issue costs 16,050 16,696 Other 84,020 80,760 ------------ ------------ Total deferred debits 319,414 338,501 ------------ ------------ TOTAL ASSETS $ 6,849,339 $ 6,521,807 ============ ============
See Notes to Condensed Financial Statements. 5 ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS (Unaudited) CAPITALIZATION AND LIABILITIES (Dollars in Thousands)
March 31, December 31, 2003 2002 ------------ ------------ CAPITALIZATION: Common stock $ 178,162 $ 178,162 Additional paid-in capital 1,246,804 1,246,804 Retained earnings 793,064 819,632 Accumulated other comprehensive loss: Minimum pension liability adjustment (61,599) (61,487) Derivative instruments (17,067) (23,799) ------------ ------------ Common stock equity 2,139,364 2,159,312 Long-term debt less current maturities 2,013,632 2,217,340 ------------ ------------ Total capitalization 4,152,996 4,376,652 ------------ ------------ CURRENT LIABILITIES: Current maturities of long-term debt 208,413 3,503 Accounts payable 118,255 118,133 Accrued taxes 126,894 82,557 Accrued interest 29,489 42,608 Customer deposits 41,855 39,865 Liabilities from risk management and trading activities 88,477 59,773 Other 68,365 51,820 ------------ ------------ Total current liabilities 681,748 398,259 ------------ ------------ DEFERRED CREDITS AND OTHER: Deferred income taxes 1,222,461 1,225,552 Liabilities from risk management and trading activities - long-term 27,119 36,678 Unamortized gain - sale of utility plant 58,340 59,484 Customer advances for construction 44,179 45,513 Pension liability 169,974 156,442 Liability for asset retirement (Note 13) 223,147 -- Other 269,375 223,227 ------------ ------------ Total deferred credits and other 2,014,595 1,746,896 ------------ ------------ COMMITMENTS AND CONTINGENCIES (Note 12) TOTAL LIABILITIES AND EQUITY $ 6,849,339 $ 6,521,807 ============ ============
See Notes to Condensed Financial Statements. 6 ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, ---------------------------- 2003 2002 ------------ ------------ (Dollars in Thousands) Cash Flows from Operating Activities: Net Income $ 15,933 $ 31,763 Items not requiring cash: Depreciation and amortization 95,557 97,622 Nuclear fuel amortization 7,726 7,484 Deferred income taxes (7,706) (10,894) Change in mark-to-market (19,924) (2,402) Changes in certain current assets and liabilities: Accounts receivable 67,855 69,530 Accrued utility revenues 15,609 12,423 Materials, supplies and fossil fuel (3,202) 476 Other current assets 1,420 (748) Accounts payable (1,558) (48,768) Accrued taxes 44,337 22,478 Accrued interest (13,119) (12,298) Other current liabilities 18,534 40,372 Increase in regulatory assets (2,152) (2,096) Change in risk management trading - assets 3,881 12,062 Change in customer advances (1,334) (8,643) Change in pension liability 13,532 6,982 Change in other net long-term assets (7,435) (9,480) Change in other net long-term liabilities (1,698) (27,914) ------------ ------------ Net cash flow provided by operating activities 226,256 177,949 ------------ ------------ Cash Flows from Investing Activities: Trust fund for bond redemption (87,225) (121,668) Capital expenditures (110,264) (116,693) Capitalized interest (4,599) (4,352) Other 8,238 26,836 ------------ ------------ Net cash flow used for investing activities (193,850) (215,877) ------------ ------------ Cash Flows from Financing Activities: Issuance of long-term debt -- 369,930 Short-term borrowings - net -- (171,162) Dividends paid on common stock (42,500) (42,500) Repayment and reacquisition of long-term debt (672) (125,144) ------------ ------------ Net cash flow provided by (used for) financing activities (43,172) 31,124 ------------ ------------ Net decrease in cash and cash equivalents (10,766) (6,804) Cash and cash equivalents at beginning of period 42,549 16,821 ------------ ------------ Cash and cash equivalents at end of period $ 31,783 $ 10,017 ============ ============ Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest (excluding capitalized interest) $ 42,747 $ 40,716 Income taxes $ -- $ 34,777
See Notes to Condensed Financial Statements. 7 ARIZONA PUBLIC SERVICE COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS 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 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. In March 2003, we deposited monies with our first mortgage bond trustee to redeem the entire $33 million of outstanding First Mortgage Bonds, 8% Series due 2025, and the entire $54 million of outstanding First Mortgage Bonds, 7.25% Series due 2023. On April 7, 2003, we redeemed $33 million of our First Mortgage Bonds, 8% Series due 2025. We will redeem $54 million of our First Mortgage Bonds, 7.25% Series due 2023, on August 1, 2003. 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 following Pinnacle West Energy power plants: Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and Saguaro Unit 3. See "ACC Financing Orders" in Note 5 for additional information. 5. Regulatory Matters ELECTRIC INDUSTRY RESTRUCTURING STATE OVERVIEW 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 8 the Rules have raised considerable uncertainty about the status and pace of retail electric competition in Arizona. On March 14, 2003, the ACC issued the Track B Order, which requires us to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. 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, guarantee up to $500 million of Pinnacle West Energy debt, or a combination of both, not to exceed $500 million in the aggregate. 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. See Note 4. As required by the 1999 Settlement Agreement, on or before June 30, 2003, we will file a general rate case with the ACC. The general rate case will also address the implementation of retail rate adjustment mechanisms that were the subject of ACC hearings in April 2003. See "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: o We have reduced, and will reduce, 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; and approximately $28 million ($17 million after taxes), effective July 1, 2002. The final price reduction is to be implemented 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. o 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. o There will be 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 we will be 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. 9 o 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. o 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 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. o 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). We will not be allowed to recover $183 million net present value (in 1999 dollars) of the above amounts. 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 due to sales volume variances. o We will form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) our competitive electric assets and services at book value as of the date of transfer, and will complete the transfers no later than December 31, 2002. We will 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. 10 RETAIL ELECTRIC COMPETITION RULES The Rules approved by the ACC included the following major provisions: o They apply to virtually all Arizona electric utilities regulated by the ACC, including us. o Effective January 1, 2001, retail access became available to all of our retail electricity customers. o 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. o Affected utilities must file ACC tariffs that unbundle rates for noncompetitive services. o The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs. o 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 11 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. That decision was upheld by the Arizona Supreme Court. 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 March 2003. TRACK A ORDER On September 10, 2002, the ACC issued the Track A Order, in which the ACC, among other things: o 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 o 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 this document include, among other things, the following: 12 o The parties agreed that it would be appropriate for the ACC to consider the following matters in our upcoming general rate case, anticipated to be filed before June 30, 2003: o the generating assets to be included in our rate base, including the question of whether certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3) should be included in our rate base; o the appropriate treatment of the $234 million pretax asset write-off agreed to by us as part of the 1999 Settlement Agreement; and o the appropriate treatment of costs incurred by us in preparation for the previously anticipated transfer of generation assets to Pinnacle West Energy. o 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 requires us to solicit bids for certain estimated capacity and energy requirements for periods beginning July 1, 2003. For 2003, we will be required to solicit competitive bids for about 2,500 megawatts 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 Track B procurement process will involve the ACC Staff and an independent monitor. The Track B Order also contains requirements relating to standards of conduct between us and any of our affiliates that may participate 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 13 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: o any debt issued by us pursuant to the order must be unsecured; o the APS Loan must be callable and secured by certain Pinnacle West Energy assets; o 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); o 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; 14 o the APS Loan must have a maturity date of not more than four years, unless otherwise ordered by the ACC; o 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; o 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 o 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: o Covered Transactions less than $100 million, measured on a cumulative basis over the calendar year in which the Covered Transactions are made; o Covered Transactions by SunCor of less than $300 million through 2005, consistent with SunCor's anticipated accelerated asset sales activity during those years; o Covered Transactions related to the payment of ongoing construction costs for Pinnacle West Energy's (a) West Phoenix Unit 5, located in Phoenix, with an expected commercial operation date in mid-2003, and (b) Silverhawk plant, located near Las Vegas, with an expected commercial operation date in mid-2004; and o 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. No party filed an application for reconsideration of the Financing Order. As a result, the Financing Order is final and not subject to appeal. 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. See Note 4. 15 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. GENERAL RATE CASE AND RETAIL RATE ADJUSTMENT MECHANISMS As required by the 1999 Settlement Agreement, on or before June 30, 2003, we will file a general rate case with the ACC. In this rate case, we will update our cost of service and rate design. In addition, we expect to seek: o rate base treatment of certain power plants currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3); o recovery of the $234 million pretax asset write-off recorded by us as part of the 1999 Settlement Agreement ($140 million extraordinary charge recorded on the 1999 Statement of Income); and o recovery of costs incurred by us in preparation for the previously required transfer of generation assets to Pinnacle West Energy. The general rate case will also address 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 has 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 issued an additional white paper on the proposed Standard Market Design. The white paper makes several 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. 16 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 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 $88 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 $77 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): o 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 o 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. 17 Financial data for our business segments follows (dollars in millions): Three Months Ended Twelve Months Ended March 31, March 31, ------------------ ------------------- 2003 2002 2003 2002 ------ ------ ------ ------ Operating Revenues: Regulated electricity $ 387 $ 384 $2,063 $2,533 Marketing and trading 92 10 115 313 ------ ------ ------ ------ Total $ 479 $ 394 $2,178 $2,846 ====== ====== ====== ====== Income Before Accounting Change: Regulated electricity $ 13 $ 31 $ 179 $ 166 Marketing and trading 3 1 4 82 ------ ------ ------ ------ Total $ 16 $ 32 $ 183 $ 248 ====== ====== ====== ====== 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 the new standard 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. EITF 00-21 is effective for revenue arrangements entered into after July 1, 2003. We are currently evaluating the impacts of this new guidance, but we do not believe it will 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. In November 2002, the AICPA announced they would no longer issue general purpose SOPs. In February 2003, the FASB determined that 18 the AICPA should continue their deliberations on certain aspects of the proposed SOP. 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: o Note 9 for a new interpretation (FIN No. 46) related to VIEs; o Note 10 for a new EITF issue (EITF 02-3) related to accounting for energy trading contracts; o Note 13 for a new accounting standard (SFAS No. 143) on asset retirement obligations; o Note 15 for a new accounting standard (SFAS No. 148) on stock-based compensation; and o 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. 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. Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to consolidate the Palo Verde SPEs. However, we continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements. 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 March 31, 2003, we would have been required to assume approximately $285 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 19 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 March 31, 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, "Accounting for Derivative Instruments and Hedging Activities." 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 changes in derivative fair value of our system positions included in the Condensed Statements of Income for the three and twelve months ended March 31, 2003 and 2002 are comprised of the following (dollars in thousands): 20
Three Months Ended Twelve Months Ended March 31, March 31, ------------------- -------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Gains (losses) on the ineffective portion of derivatives qualifying for hedge accounting (a) $ 1,564 $ (111) $ 10,158 $ (3,718) Losses from the discontinuance of cash flow hedges -- (44) (9,162) (3,561) Gains (losses) from non-hedge derivatives 5,259 (1,256) (6,130) (7,265) Prior period mark-to-market losses realized upon delivery of commodities 10,443 3,813 17,043 23,368 -------- -------- -------- -------- Total pretax gain $ 17,266 $ 2,402 $ 11,909 $ 8,824 ======== ======== ======== ========
(a) Time value component of options excluded from assessment of hedge effectiveness. As of March 31, 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 21 months. During the twelve months ending March 31, 2004, we estimate that a net loss of $16 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 mark-to-market related to our risk management and trading activities are presented in two categories, consistent with our business segments: o System - our regulated electricity business segment, which consists of non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements; and o Marketing and Trading - our non-regulated, competitive business segment, which includes both non-trading and trading derivative instruments. The following table summarizes our assets and liabilities from risk management and trading activities at March 31, 2003 and December 31, 2002 (dollars in thousands): 21
March 31, 2003 Current Current Other Net Asset/ Assets Investments Liabilities Liabilities (Liability) -------- ----------- ----------- ----------- ----------- Mark-to-Market: Marketing and Trading $ 5,920 $ 57 $ (1,882) $ (229) $ 3,866 System 82,499 8,205 (86,595) (26,890) (22,781) Emission allowances - at cost -- 20,771 -- -- 20,771 -------- -------- -------- -------- -------- Total $ 88,419 $ 29,033 $(88,477) $(27,119) $ 1,856 ======== ======== ======== ======== ======== December 31, 2002 Current Current Other Net Asset/ Assets Investments Liabilities Liabilities (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 required to serve as collateral against our open positions on energy-related contracts is included in investments and other assets on the Condensed Balance Sheet. No collateral was provided at March 31, 2003. Collateral provided was $5 million at December 31, 2002. Collateral held was $3 million at March 31, 2003 and $4 million at December 31, 2002. 22 11. Comprehensive Income Components of comprehensive income for the three and twelve months ended March 31, 2003 and 2002, are as follows (dollars in thousands):
Three Months Ended Twelve Months Ended March 31, March 31, ------------------------ ------------------------ 2003 2002 2003 2002 --------- --------- --------- --------- Net income $ 15,933 $ 31,763 $ 183,513 $ 235,399 --------- --------- --------- --------- 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 (loss) on derivative instruments, net of tax (a) 8,653 24,766 22,651 (74,260) Reclassification of realized (gain) loss to income, net of tax (b) (1,921) 542 (1,427) (9,257) --------- --------- --------- --------- Total other comprehensive income (loss) 6,620 25,308 (39,409) (76,682) --------- --------- --------- --------- Comprehensive income $ 22,553 $ 57,071 $ 144,104 $ 158,717 ========= ========= ========= =========
(a) These amounts primarily include unrealized gains and losses on contracts used to hedge our forecasted 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 ISO 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, the 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 23 markets. Sellers who may actually have paid more for natural gas than the proxy prices adopted by the FERC have 40 days in which to submit necessary data to the FERC, after which a technical conference will be held. Finalization of refund amounts is expected in mid-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 have submitted additional evidence and proposed findings, which the FERC continues to consider. The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. 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 has been submitted and a FERC decision on the newly submitted evidence is expected soon. Based on public comments from the FERC, it is anticipated that this case will be sent back to the ALJ for further proceedings on spot market and balance of month transactions. Although the FERC has not yet made a final ruling in the Pacific Northwest matter nor calculated the specific refund amounts due in California, we do not expect that the resolution of these issues, as to the amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity. On March 26, 2003, FERC made public a Final Report on Price Manipulation in Western Markets, prepared by its Staff and covering spot markets in the West in 2000 and 2001. The report stated that a significant number of entities who participated in the California markets during 2000 to 2001 time period, including us, may potentially have been involved in arbitrage transactions that allegedly violated certain provisions of the ISO tariff. The report also recommended that the FERC issue an order to show cause why these transactions did not violate the ISO tariff with potential disgorgement of any unjust profits. Although we are still attempting to determine and to review the transactions at issue, we believe that we were not engaged in any such improper transactions. Based on the information available, it also appears that such transactions would not have a material adverse impact on our financial position, results of operations or liquidity. 24 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 ISO. 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 ISO 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. POWER SERVICE AGREEMENT By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, advised us that it believes we overcharged Citizens by over $50 million under a power service agreement. We believe our charges under the agreement were fully in accordance with the terms of the agreement. In addition, in testimony filed 25 with the ACC on March 13, 2002, Citizens acknowledged, based on its review, "if Citizens filed a complaint with FERC, it probably would lose the central issue in the contract interpretation dispute." We and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, Pinnacle West and Citizens entered into a power sale agreement under which Pinnacle West will supply Citizens with future specified amounts of electricity and ancillary services through May 31, 2008. This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001. 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 quarter ended March 31, 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 March 31, 2003, accumulated depreciation shown on our Condensed 26 Balance Sheets included approximately $360 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 three-month period ended March 31, 2003 (dollars in millions): Balance at January 1, 2003 $ 219 Changes attributable to: Liabilities incurred -- Liabilities settled -- Accretion expense 4 Estimated cash flow revisions -- ----- Balance at March 31, 2003 $ 223 ===== The following schedule shows the change in our pro forma liability for the periods 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 March 31, 2003 and December 31, 2002 (dollars in millions): March 31, December 31, 2003 2002 ----- ----- Trust fund assets - at cost Fixed income securities $ 115 $ 113 Domestic stock 70 68 ----- ----- Total $ 185 $ 181 ===== ===== Trust fund assets - at fair value Fixed income securities $ 124 $ 117 Domestic stock 80 77 ----- ----- Total $ 204 $ 194 ===== ===== 27 14. Intangible Assets The Company's gross intangible assets (which are primarily software) were $218 million at March 31, 2003 and $193 million at December 31, 2002. The related accumulated amortization was $107 million at March 31, 2003 and $100 million at December 31, 2002. Amortization expense for the three months ended March 31 was $6 million in 2003 and $4 million in 2002. Amortization expense for the twelve months ended March 31 was $20 million in 2003 and 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 March 31, 2003 (dollars in thousands):
Three Months Ended Twelve Months Ended March 31, March 31, --------------------- --------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Net Income: As reported $ 15,933 $ 31,763 $183,513 $235,399 Pro forma (fair value method) 15,744 31,507 182,618 233,956 Stock compensation expense (net of tax): As reported 96 -- 296 -- Pro forma (fair value method) 189 256 895 1,443
16. Other Income and Other Expense The following table provides detail of other income and other expense for the three and twelve months ended March 31, 2003 and 2002 (dollars in thousands): 28
Three Months Ended Twelve Months Ended March 31, March 31, ---------------------- ---------------------- 2003 2002 2003 2002 -------- -------- -------- -------- Other income: Environmental insurance recovery $ -- $ -- $ -- $ 12,350 Investment gains - net 904 1,787 -- -- Interest income 433 944 2,944 5,616 Miscellaneous 452 421 1,725 2,878 -------- -------- -------- -------- Total other income $ 1,789 $ 3,152 $ 4,669 $ 20,844 ======== ======== ======== ======== Other expense: Investment losses - net $ -- $ -- $ (2,013) $ (1,713) Non-operating costs (a) (2,607) (3,454) (15,577) (14,212) Miscellaneous (235) (357) (1,662) (2,755) -------- -------- -------- -------- Total other expense $ (2,842) $ (3,811) $(19,252) $(18,680) ======== ======== ======== ========
(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 March 31, 2003. We have entered into various agreements that require letters of credit for financial assurance purposes. At March 31, 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 and approximately $5 million of letters of credit related to workers' compensation 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 29 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 Twelve Months Ended March 31, March 31, ------------------ ------------------- 2003 2002 2003 2002 ------ ------ ------ ------ Electric operating revenues: Pinnacle West - marketing and trading $ 1 $ 17 $ 69 $ 67 APS Energy Services 1 -- 1 10 ------ ------ ------ ------ Total $ 2 $ 17 $ 70 $ 77 ====== ====== ====== ====== Purchased power and fuel costs: Pinnacle West - marketing and trading $ -- $ 6 $ 129 $ 44 Pinnacle West Energy(a) 14 -- 14 14 APS Energy Services 1 -- 1 -- ------ ------ ------ ------ Total $ 15 $ 6 $ 144 $ 58 ====== ====== ====== ====== (a) Includes a credit of $6 million related to mark-to-market on an intercompany contract in both the three and twelve months ended March 31, 2003, which is expected to be realized in the second quarter of 2003. 30 As of As of March 31, 2003 December 31, 2002 -------------- ----------------- Net intercompany receivables/(payables): Pinnacle West - marketing and trading $ 72 $ 135 Pinnacle West 22 (1) Pinnacle West Energy (17) (1) ----- ----- Total $ 77 $ 133 ===== ===== 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 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. 31 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: o the changes in our earnings for the three and twelve months ended March 31, 2003 and 2002; o our capital needs, liquidity and capital resources; o our business outlook and major factors that affect our financial outlook (see Note 5 and "Business Outlook" below); and o our management of market risks. We suggest this section be read along with the 2002 10-K. 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. 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): o 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 o 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 32 trading division and more information regarding our marketing and trading activities. The following table summarizes net income by business segment for the three and twelve months ended March 31, 2003 and the comparable prior year periods (dollars in millions): Three Months Ended Twelve Months Ended March 31, March 31, --------------- --------------- 2003 2002 2003 2002 ----- ----- ----- ----- Regulated electricity (a) $ 13 $ 31 $ 179 $ 166 Marketing and trading 3 1 4 82 ----- ----- ----- ----- Income before accounting change 16 32 183 248 Cumulative effect of change in accounting - net of tax (b) -- -- -- (12) ----- ----- ----- ----- Net income $ 16 $ 32 $ 183 $ 236 ===== ===== ===== ===== (a) Consistent with our October 2001 ACC filing, we entered into agreements with our affiliates to buy power through June 2003. The agreements reflect a price based on the fully-dispatchable dedication of the Pinnacle West Energy generating assets to our Native Load customers. See "Track B Order" in Note 5 for information about our competitive solicitation process for certain estimated capacity and energy requirements beginning July 1, 2003. (b) We recorded a $12 million after tax charge in June 2001 for the cumulative effect of a change in accounting for derivatives related to the adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." 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 MARCH 31, 2003 COMPARED WITH THREE-MONTH PERIOD ENDED MARCH 31, 2002 Our net income for the three months ended March 31, 2003 was $16 million compared with $32 million for the prior year. The period-to-period decrease of $16 million was primarily due to: 33 o higher operating costs primarily related to the timing of power plant overhauls and higher pension and other postretirement benefit costs ($7 million, after tax); o decreased earnings contributions from our regulated electricity activities, reflecting retail electricity price decreases, the effects of milder weather and higher replacement power costs for plant outages, partially offset by retail customer growth, ($11 million, after tax); and o other miscellaneous factors ($1 million, after tax). The above decreases were partially offset by higher earnings contributions from our marketing and trading activities, reflecting increases in generation sales other than Native Load ($3 million, after tax). For additional details, see the following discussion. 34 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 $ (28) Higher retail sales volumes due to customer growth, excluding weather effects 7 Change in mark-to-market for hedged natural gas and purchased power costs for future delivery 18 Effects of milder weather on retail sales (6) Retail electricity price reductions effective July 1, 2002 (5) Higher replacement power costs from plant outages due to higher market prices and more unplanned outages (4) ------ Net decrease in regulated electricity segment gross margin (18) ------ Marketing and trading segment gross margin: Increase in generation sales other than Native Load due to higher sales volumes, partially offset by lower unit margins 5 Lower realized wholesale margins net of related mark-to-market reversals due to lower prices, partially offset by higher volumes 1 Lower mark-to-market gains for future delivery due to lower market liquidity and higher price volatility (1) ------ Net increase in marketing and trading segment gross margin 5 ------ Net decrease in regulated electricity and marketing and trading segments' gross margins (13) Higher operations and maintenance expense related to increased operating costs related to the timing of power plant overhauls and increased pension and other postretirement benefit costs (13) ------ Net decrease in income before income taxes (26) Lower income taxes primarily due to lower income 10 ------ Net decrease in net income $ (16) ======
REGULATED ELECTRICITY SEGMENT GROSS MARGIN Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $3 million higher in the three months ended March 31, 2003, compared with the same period in the prior year as a result of: o increased revenues related to traditional wholesale sales as a result of higher sales volumes and higher prices ($1 million); o decreased retail revenues related to milder weather ($11 million); o increased retail revenues related to customer growth, excluding weather effects ($14 million); o decreased retail revenues related to a reduction in retail electricity prices ($5 million); and o other miscellaneous factors ($4 million, net increase). 35 Regulated electricity segment purchased power and fuel costs were $21 million higher in the three months ended March 31, 2003, compared with the same period in the prior year as a result of: o increased costs related to traditional wholesale sales as a result of higher sales volumes and higher prices ($1 million); o increased purchased power and fuel costs due to higher hedged gas and power prices, net of mark-to-market reversals ($10 million); o decreased costs related to the effects of milder weather on retail sales ($5 million); o increased costs related to retail sales growth, excluding weather effects ($7 million); o increased replacement power costs for power plant outages due to higher market prices and more unplanned outages ($4 million); and o other miscellaneous factors ($4 million, net increase). MARKETING AND TRADING SEGMENT GROSS MARGIN Marketing and trading segment revenues were $81 million higher in the three months ended March 31, 2003, compared with the same period in the prior year as a result of: o increased revenues from generation sales other than Native Load primarily due to higher prices and higher sales volumes ($37 million); o higher realized wholesale revenues net of related mark-to-market reversals primarily due to higher volumes ($46 million); and o lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and higher price volatility ($2 million). Marketing and trading segment purchased power and fuel costs were $76 million higher in the three months ended March 31, 2003, compared to the same period in the prior year as a result of: o increased fuel costs related to generation sales other than Native Load primarily because of higher natural gas prices and higher sales volumes ($32 million); o increased purchased power costs related to other realized marketing activities in the current period primarily due to higher volumes and higher prices ($45 million); o change in mark-to-market fuel costs for future delivery ($1 million decrease). OTHER INCOME STATEMENT ITEMS The increase in operations and maintenance expense of $13 million was due to increased operating costs related to the timing of power plant overhauls, increased pension and other postretirement benefit costs and other costs. 36 OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2003 COMPARED WITH TWELVE-MONTH PERIOD ENDED MARCH 31, 2002 Our net income for the twelve months ended March 31, 2003 was $183 million compared with $236 million for the prior year. Included in the 2002 period was a $12 million after tax charge for the cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133. Our income before accounting change for the twelve months ended March 31, 2003 was $183 million compared with $248 million for the prior year. The period-to-period decrease of $65 million was primarily due to: o lower earnings contributions from our marketing and trading activities, reflecting lower liquidity and lower price volatility in the wholesale power markets in the western United States ($77 million, after tax); o higher operations and maintenance expenses primarily related to the 2002 severance costs and higher benefit costs ($29 million, after tax); o lower other income primarily due to an insurance recovery of environmental remediation costs in 2002 ($10 million, after tax); o higher property taxes due to higher plant balances ($4 million, after tax); and o higher interest expense primarily due to higher debt balances ($3 million, after tax). The above decreases were partially offset by: o increased earnings contributions from our regulated electricity activities, reflecting lower replacement power costs for power plant outages, retail customer growth and higher average usage per customer and lower purchased power costs related to the 2001 generation reliability program (the addition of generating capability to enhance reliability for the summer of 2001), partially offset by the effects of milder weather, and retail electricity price decreases ($48 million, after tax); and o lower depreciation and amortization expense primarily related to lower regulatory asset amortization, in accordance with the 1999 Settlement Agreement ($10 million, after tax). For additional details, see the following discussion. 37 The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
Increase (Decrease) ---------- Regulated electricity segment gross margin: Lower replacement power costs from plant outages due to lower market prices and fewer unplanned outages $ 74 Higher retail sales volumes due to customer growth and higher average usage, excluding weather effects 43 Effects of milder weather on retail sales (40) Retail electricity price reductions effective July 1, 2001 and July 1, 2002 (27) Change in mark-to-market for hedged natural gas and purchased power costs for future delivery 15 Changes related to purchased power contracts with Enron and its affiliates in fourth quarter 2001 13 Increased purchased power and fuel costs due to higher hedged gas and power prices (24) Lower purchased power and fuel costs related to the 2001 reliability program 30 Miscellaneous factors, net (5) ------ Net increase in regulated electricity segment gross margin 79 ------ Marketing and trading segment gross margin: Decrease in generation sales other than Native Load due to lower market prices, partially offset by higher sales volumes (25) Lower realized wholesale margins net of related mark-to-market reversals due to lower prices, partially offset by higher volumes (24) Lower mark-to-market gains for future delivery due to lower market liquidity and lower price volatility (79) ------ Net decrease in marketing and trading segment gross margin (128) ------ Net decrease in regulated electricity and marketing and trading segments' gross margins (49) Higher operations and maintenance expense related primarily to 2002 severance costs of approximately $34 million, partially offset by lower generation reliability costs (48) Lower depreciation primarily related to lower regulatory asset amortization 17 Higher taxes other than income taxes due to increased property taxes on higher property balances (7) Lower other income primarily due to a 2001 insurance recovery of environmental remediation costs (16) Higher net interest expense primarily due to higher debt balances and lower capitalized interest (6) Other miscellaneous factors, net (1) ------ Net decrease in income before income taxes (110) Lower income taxes primarily due to lower income 45 ------ Net decrease in income before accounting change $ (65) ======
38 REGULATED ELECTRICITY SEGMENT GROSS MARGIN Regulated electricity segment revenues related to our regulated retail and wholesale electricity businesses were $470 million lower in the twelve months ended March 31, 2003, compared with the same period in the prior year as a result of: o decreased revenues related to traditional wholesale sales as a result of lower prices and lower sales volumes ($39 million); o decreased revenues related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes ($421 million); o decreased retail revenues related to milder weather ($63 million); o increased retail revenues related to customer growth and higher average usage, excluding weather effects ($67 million); o decreased retail revenues related to reductions in retail electricity prices ($27 million); and o other miscellaneous factors ($13 million, net increase). Regulated electricity segment purchased power and fuel costs were $549 million lower in the twelve months ended March 31, 2003, compared with the same period in the prior year as a result of: o decreased costs related to traditional wholesale sales as a result of lower prices and lower sales volumes ($39 million); o decreased costs related to retail load hedge management wholesale sales, primarily as a result of lower prices and lower sales volumes, partially offset by higher hedged purchased power and fuel costs ($397 million); o decrease in mark-to-market for hedged natural gas and purchased power costs for future delivery ($15 million); o decreased costs related to the effects of milder weather on retail sales ($23 million); o increased costs related to retail sales growth, excluding weather effects ($24 million); o decreased replacement power costs for power plant outages due to lower market prices and fewer unplanned outages ($74 million); o charges in 2001 related to purchased power contracts with Enron and its affiliates ($13 million, net decrease); o lower purchased power costs related to 2001 generation reliability program ($30 million); and o miscellaneous factors ($18 million, net increase). MARKETING AND TRADING SEGMENT GROSS MARGIN Marketing and trading segment revenues were $198 million lower in the twelve months ended March 31, 2003, compared with the same period in the prior year as a result of: 39 o decreased revenues from generation sales other than Native Load primarily due to higher sales volumes, partially offset by lower market prices ($11 million); o lower realized wholesale revenues net of related mark-to-market reversals primarily due to lower prices partially offset by higher volumes ($111 million); and o lower mark-to-market gains for future delivery primarily as a result of lower market liquidity and lower price volatility ($76 million). Marketing and trading segment purchased power and fuel costs were $70 million lower in the twelve months ended March 31, 2003, compared to the same period in the prior year as a result of: o increased fuel costs related to generation sales other than Native Load primarily because of higher sales volumes ($14 million); o decreased purchased power costs related to other realized marketing activities in the current period primarily due to lower prices partially offset by higher volumes ($87 million); and o change in mark-to-market fuel costs for future delivery ($3 million increase). OTHER INCOME STATEMENT ITEMS The increase in operations and maintenance expense of $48 million was due to severance costs of $34 million related to a 2002 voluntary workforce reduction, increased pension and other postretirement benefit costs of $9 million and other costs of $5 million. The decrease in depreciation and amortization expense of $17 million primarily related to lower regulatory amortization, in accordance with the 1999 Settlement Agreement. The increase in taxes other than income taxes of $7 million is primarily due to increased property taxes on higher property balances. Other income decreased $16 million primarily due to an insurance recovery recorded in 2001 related to environmental remediation costs and other costs. Net interest expense increased $6 million primarily because of higher debt balances. 40 LIQUIDITY AND CAPITAL RESOURCES CAPITAL EXPENDITURE REQUIREMENTS The following table summarizes the actual capital expenditures for the three months ended March 31, 2003 and estimated capital expenditures for the next three years (dollars in millions): Three Months Estimated Ended March 31, ------------------------------ 2003 2003 2004 2005 ---- ---- ---- ---- Delivery $ 73 $273 $275 $329 Generation (a) 35 123 99 164 Other 1 5 5 5 ---- ---- ---- ---- Total $109 $401 $379 $498 ==== ==== ==== ==== (a) As discussed in Note 5 under "General Rate Case and Retail Rate Adjustment Mechanisms," as part of our 2003 general rate case, we intend to seek rate base treatment of certain power plants in Arizona currently owned by Pinnacle West Energy (specifically, Redhawk Units 1 and 2, West Phoenix Units 4 and 5 and Saguaro Unit 3). 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. These projects are periodic in nature and are driven by strong regional customer growth. We expect to spend about $105 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 $145 million, which will be spent from 2003 through 2008. In 2003 through 2005, $94 million of the costs are included in the generation capital expenditures table above and would be funded with internally-generated cash or external financings. 41 CAPITAL RESOURCES AND CASH REQUIREMENTS CONTRACTUAL OBLIGATIONS The following table summarizes actual contractual requirements for the three months ended March 31, 2003 and estimated contractual commitments for the next five years and thereafter (dollars in millions):
Actual ------ Three Months Estimated Ended ------------------------------------------------------------- March 31, There- 2003 2003 2004 2005 2006 2007 after ------ ------ ------ ------ ------ ------ ------ Long-term debt payments $ -- $ -- $ 205 $ 400 $ 84 $ -- $1,518 Capital lease payments 1 4 3 3 3 2 5 Operating lease payments 2 59 59 59 59 59 456 Purchase power and fuel commitments 53 164 85 28 31 17 162 ------ ------ ------ ------ ------ ------ ------ Total contractual commitments $ 56 $ 227 $ 352 $ 490 $ 177 $ 78 $2,141 ====== ====== ====== ====== ====== ====== ======
OFF-BALANCE SHEET ARRANGEMENTS 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. 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. Based on our preliminary assessment of FIN No. 46, we do not believe we will be required to consolidate the Palo Verde SPEs. However, we continue to evaluate the requirements of the new guidance to determine what impact, if any, it will have on our financial statements. 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 March 31, 2003, we would have been required to assume approximately $285 million of debt and pay the equity participants approximately $200 million. 42 CREDIT RATINGS The ratings of our securities as of May 12, 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. All of our credit ratings remain investment grade. Moody's Standard & Poor's Fitch ------- ----------------- ----- Senior secured A3 A- A- Senior unsecured Baa1 BBB BBB+ Secured lease obligation bonds Baa2 BBB BBB Commercial paper P-2 A-2 F-2 OUTLOOK Stable Stable Negative (a) (a) This rating affects all of the above debt ratings with the exception of our commercial paper rating. DEBT PROVISIONS Our significant debt covenants include a debt-to-total-capitalization ratio and an interest coverage test. 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 March 31, 2003, our ratio was approximately 49%. The provisions regarding interest coverage require a minimum cash coverage of two times the interest requirements. The coverage is approximately 5 times for our bank agreements and 14 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 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. 43 CAPITAL REQUIREMENTS AND RESOURCES Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. On April 4, 2003, the ACC issued the Financing Order, which permits 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. See "ACC Financing Orders" in Note 5 for additional information. 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 following Pinnacle West Energy power plants: Redhawk Units 1 and 2, West Phoenix Units 4 and 5, and Saguaro Unit 3. See "ACC Financing Orders" in Note 5 for additional information. 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 March 31, 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. In March 2003, we deposited monies with our first mortgage bond trustee to redeem the entire $33 million of outstanding First Mortgage Bonds, 8% Series due 2025, and the entire $54 million of outstanding First Mortgage Bonds, 7.25% Series due 2023. On April 7, 2003, we redeemed $33 million of our First Mortgage Bonds, 8% Series due 2025. We will redeem $54 million of our First Mortgage Bonds, 7.25% Series due 2023, on August 1, 2003. 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 the pension obligation. Pinnacle West elected to contribute cash to the pension plan in each of the last five years; the minimum required contributions during each of those years was zero. Specifically, Pinnacle West contributed $27 million for 2002, $24 million for 2001, $44 million for 2000, $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. Pinnacle West currently forecasts a pension contribution in 2003 of approximately $50 million, all or part of which may be required. If the fund performance continues to decline as a result of a continued decline in equity markets, larger contributions may be required in future years. 44 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 10K except for discussion contained herein 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 "Electric Industry Restructuring - State" in Note 5 for a discussion of ACC regulatory matters, including the implementation of the Track B competitive procurement process and our upcoming general rate case. WHOLESALE POWER MARKET CONDITIONS The marketing and trading division, which Pinnacle West moved to us in early 2003 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 our transfer of generating assets to Pinnacle West Energy, focuses primarily on managing our purchased power and fuel risks in connection with our costs of serving retail customer demand. 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. 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 45 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. RETAIL RATE REDUCTIONS. 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 is to be implemented July 1, 2003. See "1999 Settlement Agreement" 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, new generating plants being placed in service and our hedging program for managing such costs. 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, changes in regulatory asset amortization and our generation construction program. 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 in Arizona. Although some very limited retail competition existed in our service area in 1999 and 2000, there are 46 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 99.3, 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. 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 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 price caps and other market constraints imposed by the FERC; regional economic and market conditions, including the California energy situation and 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; the effect of conservation programs on energy usage; 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. 47 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. We adopted the EITF 02-3 guidance for all contracts in the fourth quarter of 2002. 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. 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. 48 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: o System - our regulated electricity business segment, which consists of non-trading derivative instruments that hedge our purchases and sales of electricity and fuel for our Native Load requirements; and o Marketing and Trading - our non-regulated, competitive business segment, which includes both non-trading and trading derivative instruments. The following tables show the changes in mark-to-market of our system and marketing and trading derivative positions for the three months ended March 31, 2003 and 2002 (dollars in millions): Three Months Ended Three Months Ended March 31, 2003 March 31, 2002 ------------------- ------------------- Marketing Marketing and and System Trading System Trading ------ ------- ------ ------- Mark-to-market of net positions at beginning of period $ (50) $ -- $(107) $ -- Change in mark-to-market gains (losses) for future period deliveries 5 4 (1) -- Changes in cash flow hedges recorded in OCI 14 -- 41 -- Ineffective portion of changes in fair value recorded in earnings 2 -- -- -- Mark-to-market losses realized during the period 6 -- 3 -- ----- ----- ----- ----- Mark-to-market of net positions at end of period $ (23) $ 4 $ (64) $ -- ===== ===== ===== ===== As of March 31, 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 $22 million, compared to a $24 million decrease that would have been realized as of March 31, 2002. A hypothetical favorable price movement of 10% would have increased the fair market value of these contracts by approximately $23 million, compared to a $26 million increase that would have been realized as of March 31, 2002. These contracts are hedges of our forecasted purchases of natural gas. The 49 impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. CREDIT RISK We are exposed to losses in the event of 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. 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 As of a date within 90 days of the date of this report (the "Evaluation Date"), we carried out an evaluation, under the supervision and with the participation of our management, including our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-14 and 15d-14 under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based upon this evaluation, our President and Chief Executive Officer and our Senior Vice President and Chief Financial Officer, concluded that, as of the Evaluation Date, our disclosure controls and procedures were adequate to ensure that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms. There were no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of the evaluation, including any corrective actions with regard to significant deficiencies and internal weaknesses. 50 PART II - OTHER INFORMATION 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. 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 The EPA had previously advised us that the EPA considers us to be a "potentially responsible party" in the Indian Bend Wash Superfund Site, South Area. See "Environmental Matters - Superfund" in Part I, Item 1 of the 2002 10-K. We, the EPA, the United States Department of Justice, the Attorney General for the State of Arizona, and ADEQ have reached an agreement (in the form of a Consent Decree) to settle this matter. UNITED STATES OF AMERICA AND STATE OF ARIZONA, EX REL. V. ARIZONA PUBLIC SERVICE COMPANY, Civil Action No. CIV03-767PHXPGR, In the United States District Court for the District of Arizona. Under the terms of the proposed Consent Decree, we will pay $2.72 million. Following the expiration of a thirty (30) day comment period, the Department of Justice will move for the Consent Decree to be approved by the Court, if appropriate in light of any public comment. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits EXHIBIT NO. DESCRIPTION ----------- ----------- 12.1 Ratio of Earnings to Fixed Charges 99.1 Certification of Jack E. Davis, the Registrant's principal executive officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.2 Certification of Donald E. Brandt, the Registrant's principal financial officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 99.3 APS Risk Factors In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below: 51
ORIGINALLY FILED DATE EXHIBIT NO. DESCRIPTION AS EXHIBIT: FILE NO.(a) EFFECTIVE ----------- ----------- -------------------- ----------- --------- 3.1 Articles of Incorporation 4.2 to Form S-3 1-4473 9-29-93 restated as of May 25, Registration Nos. 1988 33910 and 33--55248 by means of September 24, 1993 Form 8-K Report 3.2 Bylaws, amended as of 3.2 to Pinnacle West 1-8962 11-14-02 September 18, 2002 September 2002 Form 10-Q Report 10.1 Employment 10.1 to Pinnacle West 1-8962 5-15-03 Agreement dated March 2003 Form February 27, 2003 10-Q Report between APS and James M. Levine 10.2 Third Supplemental 10.2 to Pinnacle West 1-8962 5-15-03 Indenture dated as of March 2003 Form 10-Q November 1, 2002 Report 10.3 Third Amendment to 10.3 to Pinnacle West 1-8962 5-15-03 the Pinnacle West March 2003 Form 10-Q Capital Corporation, Report Arizona Public Service Company, SunCor Development Company and El Dorado Investment Company Deferred Compensation Plan 99.1 ACC Decision 65796 99.3 to Pinnacle West 1-8962 5-15-03 dated April 4, 2003 March 2003 Form 10-Q (Financing Order)
(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. 52 (b) Reports on Form 8-K During the quarter ended March 31, 2003, and the period from April 1 through May 14, 2003, we filed the following reports on Form 8-K: Report dated January 15, 2003 regarding NAC losses and Pinnacle West's earnings outlook. Report dated January 30, 2003 regarding an ACC ALJ's recommended Track B order. Report dated February 24, 2003 regarding reclassifications of revenue and costs and other income and expenses from electricity trading activities to a net basis of reporting. Report dated February 27, 2003 regarding the ACC Track B decision. Report dated March 11, 2003 regarding an ACC ALJ's recommended approval, subject to certain conditions, of APS' financing application. Report dated March 27, 2003 regarding ACC approval of the financing application. 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. 53 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated: May 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) CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER CERTIFICATIONS I, Jack E. Davis, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Arizona Public Service Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this quarterly report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; 54 b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 14, 2003. Jack E. Davis -------------------------------------------- Jack E. Davis Title: President and Chief Executive Officer CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER CERTIFICATIONS I, Donald E. Brandt, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Arizona Public Service Company; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the period presented in this quarterly report; 55 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: May 14, 2003. Donald E. Brandt -------------------------------------------- Donald E. Brandt Title: Senior Vice President and Chief Financial Officer 56