10-Q 1 e-5640.txt QUARTERLY REPORT FOR THE PERIOD ENDED 09/30/2000 FORM 10-Q Securities and Exchange Commission Washington, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2000 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 N. 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 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 November 14, 2000: 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 APS Energy Services - APS Energy Services Company, Inc., a subsidiary of Pinnacle West Company - Arizona Public Service Company EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Application of FASB Statements No. 71, Accounting for the Effects of Certain Types of Regulation, and No. 101, Regulated Enterprises -- Accounting for the Discontinuation of Application of FASB Statement No. 71" EPA - United States Environmental Protection Agency FASB - Financial Accounting Standards Board FERC - United States Federal Energy Regulatory Commission Four Corners - Four Corners Power Plant ITC - Investment tax credit June 10-Q - Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2000 MW - Megawatts NGS - Navajo Generating Station 1999 10-K - Arizona Public Service Company Annual Report on Form 10-K for the fiscal year ended December 31, 1999 Palo Verde - Palo Verde Nuclear Generating Station Pinnacle West - Pinnacle West Capital Corporation Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West subsidiary SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" SFAS No. 133 - Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" Salt River Project - Salt River Project Agricultural Improvement and Power District Settlement Agreement - APS' Settlement Agreement approved by the ACC in 1999 -2- PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Three Months Ended September 30, -------------------------- 2000 1999 ----------- ----------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .............................. $ 1,565,622 $ 867,504 ----------- ----------- FUEL EXPENSES: Fuel for electric generation ........................... 100,036 68,137 Purchased power ........................................ 977,103 332,617 ----------- ----------- Total ............................................... 1,077,139 400,754 ----------- ----------- OPERATING REVENUES LESS FUEL EXPENSES .................... 488,483 466,750 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses ..... 110,827 107,188 Depreciation and amortization .......................... 97,383 94,184 Income taxes ........................................... 93,998 92,286 Other taxes ............................................ 25,629 22,178 ----------- ----------- Total ............................................... 327,837 315,836 ----------- ----------- OPERATING INCOME ......................................... 160,646 150,914 ----------- ----------- OTHER INCOME (DEDUCTIONS): Other - net ............................................ (3,544) 620 Income taxes ........................................... 1,424 13,283 ----------- ----------- Total ............................................... (2,120) 13,903 ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS ........................ 158,526 164,817 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt ............................. 33,681 31,409 Interest on short-term borrowings ...................... 1,634 2,775 Debt discount, premium and expense ..................... 1,656 1,847 Capitalized interest ................................... (2,676) (722) ----------- ----------- Total ............................................... 34,295 35,309 ----------- ----------- INCOME BEFORE EXTRAORDINARY CHARGE ....................... 124,231 129,508 Extraordinary charge - net of income taxes of $94,115 .. -- 139,885 ----------- ----------- EARNINGS (LOSS) FOR COMMON STOCK ......................... $ 124,231 $ (10,377) =========== ===========
See Notes to Condensed Financial Statements. -3- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Nine Months Ended September 30, -------------------------- 2000 1999 ----------- ----------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .............................. $ 2,730,997 $ 1,792,921 ----------- ----------- FUEL EXPENSES: Fuel for electric generation ........................... 232,655 178,536 Purchased power ........................................ 1,259,151 457,319 ----------- ----------- Total ............................................... 1,491,806 635,855 ----------- ----------- OPERATING REVENUES LESS FUEL EXPENSES .................... 1,239,191 1,157,066 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses ..... 323,938 313,884 Depreciation and amortization .......................... 289,856 286,856 Income taxes ........................................... 189,706 166,945 Other taxes ............................................ 76,606 73,008 ----------- ----------- Total ............................................... 880,106 840,693 ----------- ----------- OPERATING INCOME ......................................... 359,085 316,373 ----------- ----------- OTHER INCOME (DEDUCTIONS): Other - net ............................................ (3,856) (3,799) Income taxes ........................................... 1,550 24,765 ----------- ----------- Total ............................................... (2,306) 20,966 ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS ........................ 356,779 337,339 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt ............................. 99,626 98,833 Interest on short-term borrowings ...................... 6,754 6,779 Debt discount, premium and expense ..................... 5,124 5,604 Capitalized interest ................................... (7,582) (6,721) ----------- ----------- Total ............................................... 103,922 104,495 ----------- ----------- INCOME BEFORE EXTRAORDINARY CHARGE ....................... 252,857 232,844 Extraordinary charge - net of income taxes of $94,115 .. -- 139,885 ----------- ----------- NET INCOME ............................................... 252,857 92,959 PREFERRED STOCK DIVIDEND REQUIREMENTS .................... -- 1,016 ----------- ----------- EARNINGS FOR COMMON STOCK ................................ $ 252,857 $ 91,943 =========== ===========
See Notes to Condensed Financial Statements -4- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Twelve Months Ended September 30, -------------------------- 2000 1999 ----------- ----------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .............................. $ 3,230,874 $ 2,236,447 ----------- ----------- FUEL EXPENSES: Fuel for electric generation ........................... 297,968 235,629 Purchased power ........................................ 1,353,477 516,996 ----------- ----------- Total ............................................... 1,651,445 752,625 ----------- ----------- OPERATING REVENUES LESS FUEL EXPENSES .................... 1,579,429 1,483,822 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses ..... 447,783 419,910 Depreciation and amortization .......................... 385,057 384,333 Income taxes ........................................... 214,776 196,344 Other taxes ............................................ 100,177 95,970 ----------- ----------- Total ............................................... 1,147,793 1,096,557 ----------- ----------- OPERATING INCOME ......................................... 431,636 387,265 ----------- ----------- OTHER INCOME (DEDUCTIONS): Other - net ............................................ (11,594) (9,067) Income taxes ........................................... 9,312 31,302 ----------- ----------- Total ............................................... (2,282) 22,235 ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS ........................ 429,354 409,500 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt ............................. 133,469 132,798 Interest on short-term borrowings ...................... 8,247 8,841 Debt discount, premium and expense ..................... 6,843 7,439 Capitalized interest ................................... (7,540) (10,357) ----------- ----------- Total ............................................... 141,019 138,721 ----------- ----------- INCOME BEFORE EXTRAORDINARY CHARGE ....................... 288,335 270,779 Extraordinary charge - net of income taxes of $94,115 .. -- 139,885 ----------- ----------- NET INCOME ............................................... 288,335 130,894 PREFERRED STOCK DIVIDEND REQUIREMENTS .................... -- 3,059 ----------- ----------- EARNINGS FOR COMMON STOCK ................................ $ 288,335 $ 127,835 =========== ===========
See Notes to Condensed Financial Statements -5- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ASSETS (Unaudited) September 30, December 31, 2000 1999 ----------- ----------- (Thousands of Dollars) UTILITY PLANT: Electric plant in service and held for future use $ 7,726,945 $ 7,545,575 Less accumulated depreciation and amortization ... 3,193,589 3,026,041 ----------- ----------- Total ......................................... 4,533,356 4,519,534 Construction work in progress .................... 215,639 184,764 Nuclear fuel, net of amortization ................ 51,274 49,114 ----------- ----------- Utility plant - net ........................... 4,800,269 4,753,412 ----------- ----------- INVESTMENTS AND OTHER ASSETS ..................... 192,725 208,457 ----------- ----------- CURRENT ASSETS: Cash and cash equivalents ........................ 63,365 7,477 Accounts receivable: Service customers ............................. 606,040 201,704 Other ......................................... 78,036 35,684 Allowance for doubtful accounts ............... (2,168) (1,538) Accrued utility revenues ......................... 111,315 72,919 Materials and supplies, at average cost .......... 73,506 69,977 Fossil fuel, at average cost ..................... 14,553 21,869 Deferred income taxes ............................ 8,163 8,163 Other ............................................ 39,324 30,885 ----------- ----------- Total current assets .......................... 992,134 447,140 ----------- ----------- DEFERRED DEBITS: Regulatory assets ................................ 502,595 613,729 Unamortized debt issue costs ..................... 13,143 15,172 Other ............................................ 47,544 79,714 ----------- ----------- Total deferred debits ......................... 563,282 708,615 ----------- ----------- TOTAL ......................................... $ 6,548,410 $ 6,117,624 =========== =========== See Notes to Condensed Financial Statements. -6- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS LIABILITIES (Unaudited) September 30, December 31, 2000 1999 ---------- ---------- (Thousands of Dollars) CAPITALIZATION: Common stock ...................................... $ 178,162 $ 178,162 Additional paid-in capital ........................ 1,246,804 1,246,804 Retained earnings ................................. 683,565 558,208 ---------- ---------- Common stock equity ............................ 2,108,531 1,983,174 Long-term debt less current maturities ............ 2,056,282 1,997,400 ---------- ---------- Total capitalization ........................... 4,164,813 3,980,574 ---------- ---------- CURRENT LIABILITIES: Commercial paper .................................. 2,000 38,300 Current maturities of long-term debt .............. 4,887 114,711 Accounts payable .................................. 472,090 170,662 Accrued taxes ..................................... 208,857 62,858 Accrued interest .................................. 23,600 32,299 Customer deposits ................................. 23,892 24,682 Other ............................................. 69,322 26,248 ---------- ---------- Total current liabilities ...................... 804,648 469,760 ---------- ---------- DEFERRED CREDITS AND OTHER: Deferred income taxes ............................. 1,104,516 1,178,085 Unamortized gain - sale of utility plant .......... 69,780 73,212 Customer advances for construction ................ 41,128 38,150 Other ............................................. 363,525 377,843 ---------- ---------- Total deferred credits and other ............... 1,578,949 1,667,290 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 9) TOTAL .......................................... $6,548,410 $6,117,624 ========== ========== See Notes to Condensed Financial Statements. -7- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, -------------------------- 2000 1999 ----------- ----------- (Thousands of Dollars) Cash Flows from Operating Activities: NET INCOME ......................................... $ 252,857 $ 92,959 Items not requiring cash: Depreciation and amortization .................... 289,856 286,856 Nuclear fuel amortization ........................ 23,139 24,306 Deferred income taxes - net ...................... (47,627) (30,977) Deferred investment tax credit - net ............. -- (23,503) Extraordinary charge, net of income taxes - net .. -- 139,885 Changes in certain current assets and liabilities: Accounts receivable - net ........................ (446,058) (102,315) Accrued utility revenues ......................... (38,396) (33,543) Materials, supplies and fossil fuel .............. 3,787 (4,758) Other current assets ............................. (8,439) (2,174) Accounts payable ................................. 298,198 78,937 Accrued taxes .................................... 145,999 126,147 Accrued interest ................................. (8,699) (8,838) Other current liabilities ........................ 42,284 7,897 Other - net ........................................ 32,302 (18,750) ----------- ----------- Net cash flow provided by operating activities .. 539,203 532,129 ----------- ----------- Cash Flows from Investing Activities: Capital expenditures ............................... (278,282) (228,540) Capitalized interest ............................... (7,582) (6,721) Other .............................................. 18,349 592 ----------- ----------- Net cash flow used for investing activities .... (267,515) (234,669) ----------- ----------- Cash Flows from Financing Activities: Long-term debt ..................................... 300,000 142,952 Short-term borrowings - net ........................ (36,300) 44,670 Dividends paid on common stock ..................... (127,500) (127,500) Dividends paid on preferred stock .................. -- (1,393) Repayment of preferred stock ....................... -- (96,499) Repayment and reacquisition of long-term debt ...... (352,000) (260,381) ----------- ----------- Net cash flow used for financing activities .... (215,800) (298,151) ----------- ----------- Net increase (decrease) in cash and cash equivalents.. 55,888 (691) Cash and cash equivalents at beginning of period ..... 7,477 5,558 ----------- ----------- Cash and cash equivalents at end of period ........... $ 63,365 $ 4,867 =========== =========== Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest (excluding capitalized interest) ........ $ 96,723 $ 107,677 Income taxes ..................................... $ 133,817 $ 102,299
See Notes to Condensed Financial Statements. -8- 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 extraordinary charge . 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 1999 10-K. We have reclassified certain prior year amounts to conform to the current year presentation. 2. Weather conditions and wholesale power marketing and trading activities can have significant impacts on our results for interim periods. For these and other reasons, 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. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the nine months ended September 30, 2000. 5. Regulatory Accounting For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. During 1997, the Emerging Issues Task Force (EITF) of the FASB issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be discontinued no later than when legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated, which could result in write-downs or write-offs of physical and/or regulatory assets. Additionally, the EITF determined that regulatory assets should not be written off if they are to be recovered from a portion of the entity which continues to apply SFAS No. 71. The Settlement Agreement was approved by the ACC in September 1999 (see Note 6 for a discussion of the agreement). Consequently, we have discontinued the application of SFAS No. 71 for our generation operations. This application means that the generation assets were tested for impairment and the portion of regulatory assets deemed to be unrecoverable through ongoing regulated cash flows was eliminated. We determined that the generation assets were not impaired. A regulatory disallowance removed $234 million pretax ($183 million net present value) from ongoing regulatory cash flows and was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes) was reported as an extraordinary charge on the income statement during the third quarter of 1999. Prior to the Settlement Agreement, under the 1996 regulatory agreement (see Note 6), the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period ending June 30, 2004. -9- The regulatory assets to be recovered under the 1999 Settlement Agreement are now being amortized as follows (millions of dollars): 1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $ 86 $ 18 $686 The majority of our regulatory assets relate to deferred income taxes and rate synchronization cost deferrals. The condensed balance sheets include the amounts listed below for generation assets not subject to SFAS No. 71 (thousands of dollars): September 30, December 31, 2000 1999 ----------- ----------- Electric plant in service & held for future use $ 3,819,709 $ 3,770,234 Accumulated depreciation and amortization (1,725,706) (1,641,855) Construction work in progress 82,447 67,306 Nuclear fuel, net of amortization 51,274 49,114 6. Regulatory Matters -- Electric Industry Restructuring STATE SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive Settlement Agreement with various parties, including representatives of major consumer groups, related to the implementation of retail electric competition. On September 23, 1999, the ACC voted to approve the Settlement Agreement, with some modifications. On December 13, 1999, two parties filed lawsuits challenging the ACC's approval of the Settlement Agreement. One of the parties questioned the authority of the ACC to approve the Settlement Agreement and both parties challenged several specific provisions of the Settlement Agreement. A decision on the appeals to the Settlement Agreement is not expected until later this year or next year. -10- The following are the major provisions of the Settlement Agreement, as approved: * 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 electric price reductions of 1.5% beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 million ($14 million after income taxes) included the July 1, 1999 retail price decrease of approximately $11 million ($7 million after income taxes) related to the 1996 regulatory agreement. See "1996 Regulatory Agreement" below. Based on the price reduction authorized in the Settlement Agreement, there was a retail price decrease of approximately $28 million ($17 million after taxes), or 1.5%, effective July 1, 2000. For customers having loads three MW or greater, standard offer rates will be reduced in varying annual increments that total 5% through 2002. * Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the Settlement Agreement, retroactive to July 1, 1999, and also will be subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004. * 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 the Company 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, or material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders. * We will be permitted to defer for later recovery prudent and reasonable costs of complying with the ACC electric competition rules, system benefits costs in excess of the levels included in current rates, and costs associated with our "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. * Our distribution system opened for retail access effective September 24, 1999. Customers will be eligible for retail access in accordance with the phase-in adopted by the ACC under the electric competition rules (see "Retail Electric Competition Rules" below), with an additional 140 MW being made available to eligible non-residential customers. Unless subject to judicial or regulatory restraint, we will open our distribution system to retail access for all customers on January 1, 2001. * Prior to the Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. In addition, the 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. We will not be allowed to recover $183 million net present value of the above amounts. The Settlement Agreement provides that we will have the opportunity to recover $350 million net present value through a competitive transition charge (CTC) that will remain in effect through December 31, 2004, at which time it will terminate. Any over/under-recovery will be -11- credited/debited against the costs subject to recovery under the adjustment clause described above. * We will form a separate corporate affiliate or affiliates and transfer to such affiliate(s) our generating assets and competitive services at book value as of the date of transfer, which transfer shall take place no later than December 31, 2002. See Management's Discussion and Analysis of Financial Condition and Results of Operations below for a discussion of the planned timing of the transfer. We will be allowed to defer and later collect, beginning July 1, 2004, sixty-seven percent of our costs to accomplish the required transfer of generation assets to an affiliate. * When the Settlement Agreement approved by the ACC is no longer subject to judicial review, we will move to dismiss all of our litigation pending against the ACC as of the date we entered into the Settlement Agreement. To protect our rights, we have several lawsuits pending on ACC orders relating to stranded cost recovery and the adoption and amendment of the ACC's electric competition rules, which would be voluntarily dismissed at the appropriate time under this provision. As discussed in Note 5 above, we have discontinued the application of SFAS No. 71 for our generation operations. RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to approve the rules that provide a framework for the introduction of retail electric competition in Arizona (Rules). If any of the Rules conflict with the Settlement Agreement, the terms of the Settlement Agreement govern. On December 8, 1999, we filed a lawsuit to protect our legal rights regarding the Rules. This lawsuit is pending, along with several other lawsuits on ACC orders relating to stranded cost recovery, the adoption or amendment of the Rules and the certification of competitive electric service providers. On July 12, 2000, a Maricopa County Superior Court judge issued a preliminary ruling and denied most of the substantive challenges to the Rules that had been made by certain electric cooperatives. However, he concluded that some of the Rules were invalid because of procedural deficiencies or were invalid in their application. Specifically, the judge concluded that several non-ratemaking Rules were required to be presented to the Arizona Attorney General for certification prior to becoming effective. Additionally, the judge determined that the Arizona Constitution requires the ACC to make findings regarding the fair value of property in Arizona in establishing rates for competitive electric service providers (ESPs), which rendered the rate setting provisions of the Rules invalid in the application. On November 2, 2000, the same Superior Court judge amended his July 12 preliminary ruling. This amended ruling indicated the Court's intent to accept the substantive provisions of a form of final judgment submitted by the electric cooperatives that finds the Rules in their entirety to be unconstitutional and unlawful due to failure to establish fair value rate base and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The cooperatives' proposed form of final judgment also invalidates all the ACC orders authorizing competitive electric service providers in Arizona. We do not believe either of the rulings affects the Settlement Agreement with the ACC. The Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of APS' property in the order approving the APS Settlement Agreement. -12- Although the ACC has not yet indicated what steps it intends to take after a final judgment is issued, the ACC could appeal the ruling to the Court of Appeals or could elect to take action to correct the deficiencies identified in the judge's ruling. The cooperatives or ESPs may also appeal the ruling. If the order is appealed by the ACC or any of the ESPs, including APS Energy Services, we believe that it will be automatically stayed pending further judicial review. The Rules approved by the ACC include the following major provisions: * They apply to virtually all Arizona electric utilities regulated by the ACC, including us. * The Rules require each affected utility, including us, to make available at least 20% of its 1995 system retail peak demand for competitive generation supply beginning when the ACC makes a final decision on each utility's stranded costs and unbundled rates (Final Decision Date) or January 1, 2001, whichever is earlier, and 100% beginning January 1, 2001. Under the Settlement Agreement, we will provide retail access to customers representing the minimum 20% required by the ACC and an additional 140 MW of non-residential load in 1999, and to all customers as of January 1, 2001, or such other dates as approved by the ACC. * Subject to the 20% requirement, all utility customers with single premise loads of one MW or greater will be eligible for competitive electric services on the Final Decision Date, which for our customers was the approval of the Settlement Agreement. Customers may also aggregate smaller loads to meet this one MW requirement. * Residential customers were phased in at 1.25% per quarter calculated beginning on January 1, 1999, subject to the 20% requirement above. * Electric service providers that get Certificates of Convenience and Necessity (CC&Ns) from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution. * Affected utilities must file ACC tariffs that unbundle rates for non-competitive services. * The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs. * Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate. Under the Settlement Agreement, we received a waiver to allow transfer of our generation and other competitive assets and services to affiliates no later than December 31, 2002. See Management's Discussion and Analysis of Financial Condition and Results of Operations below for a discussion of the planned timing of the transfer. -13- 1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory agreement between the ACC Staff and us. Based on the price reduction formula authorized in the agreement, the ACC approved retail price decreases (approximate) as follows (millions of dollars): Annual Electric Percentage Revenue Decrease Decrease Effective Date ---------------- -------- -------------- $49 3.4% July 1, 1996 $18 1.2% July 1, 1997 $17 1.1% July 1, 1998 $11 0.7% July 1, 1999 (a) (a) Included in the first rate reduction under the Settlement Agreement (see above). The regulatory agreement also required the parent company to infuse $200 million of common equity into us in annual payments of $50 million from 1996 through 1999. All of these equity infusions were made by December 31, 1999. LEGISLATION. In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona. The law includes the following major provisions: * Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition; * describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; and * metering and meter reading services must be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one MW (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation. GENERAL We cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operations. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position the Company and our subsidiaries to compete in the new regulatory environment. -14- FEDERAL The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. We do not expect these rules to have a material impact on our financial statements. Several electric utility industry restructuring bills have been introduced during the current congressional session. Several of these bills are written to allow consumers to choose their electricity suppliers beginning in 2000 and beyond. These bills, other bills that are expected to be introduced, and ongoing discussions at the federal level suggest a wide range of opinion that will need to be narrowed before any comprehensive restructuring of the electric utility industry can occur. 7. Nuclear Insurance The Palo Verde participants have insurance for public liability payments 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 $200 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 upon our 29.1% interest in the three Palo Verde units, our maximum potential assessment per incident 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. -15- 8. Business Segments We have two principal business segments (determined by products, services and regulatory environment) which consist of the transmission and distribution of electricity and wholesale power marketing and trading activities (delivery business segment) and the generation of electricity (generation business segment). Eliminations primarily relate to intersegment sales of electricity. Segment information for the three, nine and twelve months ended September 30, 2000 and 1999 is as follows (millions of dollars):
3 Months Ended 9 Months Ended 12 Months Ended September 30, September 30, September 30, ----------------- ------------------- ------------------- 2000 1999 2000 1999 2000 1999 ------- ----- ------- ------- ------- ------- Operating Revenues: Delivery $ 1,566 $ 867 $ 2,731 $ 1,793 $ 3,231 $ 2,236 Generation 322 266 750 662 942 852 Eliminations (322) (266) (750) (662) (942) (852) ------- ----- ------- ------- ------- ------- Total $ 1,566 $ 867 $ 2,731 $ 1,793 $ 3,231 $ 2,236 ======= ===== ======= ======= ======= ======= Income from Continuing Operations: Delivery $ 57 $ 61 $ 137 $ 115 $ 169 $ 142 Generation 67 69 116 117 119 126 ------- ----- ------- ------- ------- ------- Total $ 124 $ 130 $ 253 $ 232 $ 288 $ 268 ======= ===== ======= ======= ======= =======
As of September 30, As of December 31, 2000 1999 ------ ------ Assets: Delivery $4,238 $3,796 Generation 2,310 2,322 ------ ------ Total $6,548 $6,118 ====== ====== -16- 9. Accounting Matters In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". In June 2000, the FASB issued SFAS No. 138, which amends certain provisions of SFAS133 to clarify certain areas causing difficulties in implementation. The amendment includes expanding the normal purchase and sale exemption for supply contracts. We will adopt SFAS133 and the corresponding amendments under SFAS138 on January 1, 2001. We are currently determining the impact of SFAS133 on our consolidated results of operations and financial position; however, certain implementation issues are currently being resolved by the FASB's Derivatives Implementation Group that will significantly affect its impact. This statement should have no impact on cash flows. -17- ARIZONA PUBLIC SERVICE COMPANY ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. In this section, we explain our results of operations, general financial condition, and outlook including: * the changes in our earnings for the periods presented * the factors impacting our business, including competition * the effects of regulatory decisions on our results and outlook * our capital needs and resources and * our management of market risks. We are Arizona's largest electric utility, providing retail and wholesale electric service to the entire state with the exception of Tucson and about one-half of the Phoenix area. We also generate, sell, and deliver electricity to wholesale customers in the western United States. As discussed in Note 6, the Settlement Agreement and the Rules require us to transfer our generating assets and competitive services to one or more corporate affiliates. We plan to complete the move of our wholesale power marketing and trading activities to the parent company by the end of 2000. We plan to move certain of our non-nuclear generating facilities and related assets, as well as certain employees of our generation business unit, to Pinnacle West Energy on January 1, 2001, or as soon thereafter as requisite approvals are obtained. See Note 6 for information regarding lawsuits challenging the Settlement Agreement and the Rules. We suggest this section be read along with the 1999 10-K. Throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations, we refer to specific "Notes" in the Notes to Condensed Financial Statements in this report. These Notes add further details to the discussion. OPERATING RESULTS The following table summarizes our revenues and earnings for the three-month, nine-month and twelve-month periods ended September 30, 2000 and the comparable prior-year periods: -18- Periods ended September 30 (Unaudited) (Thousands of Dollars)
Three Months Nine Months Twelve Months ----------------------- ------------------------ ------------------------ 2000 1999 2000 1999 2000 1999 ---------- --------- ---------- ---------- ---------- ---------- Operating Revenues $1,565,622 $ 867,504 $2,730,997 $1,792,921 $3,230,874 $2,236,447 Earnings (Loss) for Common Stock (1) $ 124,231 $ (10,377) $ 252,857 $ 91,943 $ 288,335 $ 127,835
(1) Each of the 1999 periods include an extraordinary charge of $139,885 net of income taxes of $94,115. OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 Earnings for the three months ended September 30, 2000 were $124 million compared with a loss of $10 million for the same period in the prior year. The increase primarily relates to an extraordinary charge recorded in the third quarter of 1999, partially offset by lower income excluding the extraordinary charge in the third quarter of 2000. The extraordinary charge related to a regulatory disallowance that resulted from our comprehensive Settlement Agreement that was approved by the ACC in September 1999. See Notes 5 and 6 for additional information about the regulatory disallowance and the Settlement Agreement. Earnings excluding the extraordinary charge decreased $5 million over the comparable prior-year period primarily because of the completion of the amortization of ITCs in 1999, an electricity price reduction, and miscellaneous factors. Partially offsetting these factors was an increase in the contribution of wholesale power marketing and trading activities. See Note 6 for information on the price reduction. See "Income Taxes" below for a discussion of the ITC amortization. Electric operating revenues increased $ 698 million because of: * increased power marketing, trading, and wholesale revenues ($664 million) * increases in the number of customers and the average amount of electricity used by customers ($33 million) and * warmer weather impacts ($9 million). As mentioned above, these positive factors were partially offset by the effect of a reduction in retail electricity prices ($8 million). The increase in power marketing, trading, and wholesale revenues resulted from higher prices and increased activity in the western U.S. wholesale power markets. The revenues were accompanied by an increase in purchased power and fuel expenses of $602 million. -19- Fuel and purchased power expenses were also higher because of higher retail sales volumes and increased prices. Utility operations and maintenance expenses increased primarily because of higher costs related to customer growth. Property tax expense increased because of higher tax rates. Depreciation and amortization expense increased primarily because of higher plant balances. OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 Earnings for the nine months ended September 30, 2000 were $253 million compared with $92 million for the same period in the prior year. The increase primarily relates to an extraordinary charge recorded in the third quarter of 1999 and higher earnings excluding the extraordinary charge in the nine month period ended September 30, 2000. The extraordinary charge related to a regulatory disallowance that resulted from our comprehensive Settlement Agreement that was approved by the ACC in September 1999. See Notes 5 and 6 for additional information about the regulatory disallowance and the Settlement Agreement. Earnings excluding the extraordinary charge increased $21 million over the comparable prior-year period primarily because of an increase in the contribution of wholesale power marketing and trading activities. This positive factor more than offsets decreases due to the completion of the amortization of ITCs in 1999, electricity price reductions, higher utility operations and maintenance expense, and miscellaneous factors. See Note 6 for information on the price reductions. See "Income Taxes" below for a discussion of the ITC amortization. Electric operating revenues increased $938 million because of: * increased power marketing, trading, and wholesale revenues ($840 million) * increases in the number of customers and the average amount of electricity used by customers ($87 million) * warmer weather impacts ($28 million) and * miscellaneous factors ($1 million). These positive factors were partially offset by the effect of a reduction in retail electricity prices ($18 million). The increase in power marketing, trading, and wholesale revenues resulted from higher prices and increased activity in the western U.S. wholesale power markets. The revenues were accompanied by an increase in purchased power and fuel expenses of $734 million. Fuel and purchased power expenses were also higher because of higher retail sales volumes and increased prices. -20- Utility operations and maintenance expenses increased primarily because of higher costs primarily related to customer growth. OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 COMPARED WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1999 Earnings for the twelve months ended September 30, 2000 were $288 million compared with $128 million for the same period in the prior year. The increase primarily relates to an extraordinary charge recorded in the third quarter of 1999 and higher earnings excluding the extraordinary charge in the twelve month period ended September 30, 2000. The extraordinary charge related to a regulatory disallowance that resulted from our comprehensive Settlement Agreement that was approved by the ACC in September 1999. See Notes 5 and 6 for additional information about the regulatory disallowance and the Settlement Agreement. Earnings excluding the extraordinary charge increased $21 million over the comparable prior year period primarily because of an increase in the contribution of wholesale power marketing and trading activities, and an increase in the number of customers and in the average amount of electricity used by customers. These positive factors more than offset decreases due to the completion of the amortization of ITCs in 1999, reductions in retail electricity prices, higher utility operations and maintenance expenses, and miscellaneous factors. See Note 6 for information on the price reduction. See "Income Taxes" below for a discussion of the ITC amortization. Electric operating revenues increased $994 million because of: * increased power marketing, trading, and wholesale revenues ($880 million) * increases in the number of customers and the average amount of electricity used by customers ($107 million) and * warmer weather impacts ($35). These positive factors were partially offset by the effect of a reduction in retail electricity prices ($28 million). The increase in power marketing, trading, and wholesale revenues resulted primarily from increased activity in western U.S. wholesale power markets and higher prices. The revenues were accompanied by increases in purchased power and fuel expenses of $769 million. Fuel and purchased power expenses were also higher because of higher retail sales volumes and increased prices. Utility operations and maintenance expenses increased primarily because of customer growth, power marketing costs, and technology related costs. -21- INCOME TAXES As part of a 1994 rate settlement with the ACC, we accelerated amortization of substantially all deferred ITCs over a five-year period that ended on December 31, 1999. The ITC amortization decreased annual income tax expense by approximately $28 million. Beginning in 2000, no further benefits from these deferred ITCs will be reflected in income tax expense. LIQUIDITY AND CAPITAL RESOURCES For the nine months ended September 30, 2000, we incurred approximately $275 million in capital expenditures, which is approximately 59% of the most recently estimated 2000 capital expenditures. Our projected capital expenditures for the next three years are $464 million in 2000; $356 million in 2001; and $364 in 2002. These amounts include about $30-$35 million each year for nuclear fuel expenditures. Our long-term debt redemption requirements, optional repayments on long-term debt, and payment obligations on a capitalized lease are: $354 million in 2000; $252 million in 2001; and $125 million in 2002. During the nine months ended September 30, 2000, we redeemed all of our long-term debt requirements for 2000 with cash from operations and short-term borrowings. On August 7, 2000, we issued $300 million of our 7 5/8% Notes Due 2005. We expect to purchase Units 1, 2 and 3 of the West Phoenix Power Plant in December 2000. These units are currently reflected as a capitalized lease. Although provisions in our first mortgage bond indenture, articles of incorporation, and ACC financing orders establish maximum amounts of additional first mortgage bonds and preferred stock that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements. FINANCIAL OUTLOOK This section describes the major factors affecting our financial outlook. See "Liquidity and Capital Resources" for expected capital expenditures and financing requirements. See "Operating Results" for a summary of our earnings for the three-month, nine-month, and twelve-month periods ended September 30, 2000 and 1999. The electric industry is restructuring to a competitive, customer-driven environment from a regulated monopoly structure. See Note 6 for a discussion of industry restructuring developments and their potential impacts on our financial outlook. In addition to other issues, the Settlement Agreement sets forth electricity prices for its regulated electricity services and the timing for customer eligibility to select competitive energy providers. 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. The 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. -22- In our regulated retail market area, we will provide electricity services to standard-offer, full-service customers and to energy delivery customers who have chosen another provider for their electricity commodity needs (unbundled customers). Customer growth in our service territory averaged 3.9% a year for the three years 1997 through 1999; we currently expect customer growth to average 3.5% to 4% a year for 2000 through 2002. We currently estimate that electricity sales in kilowatt-hours will grow 4% to 5% a year in 2000 through 2002, before the effects of weather variations. The customer growth and sales growth referred to in this paragraph apply to energy delivery customers. As industry restructuring continues in the regulated market area, we cannot predict the number of standard offer customers that will switch to unbundled service. Bulk power marketing and trading activities will be affected by electricity prices and costs of available fuel and purchased power from time to time in the western United States, as well as competitive market conditions and regulatory and legislative changes in various state and federal jurisdictions. These factors have significantly affected our wholesale marketing and trading activities and their resultant earnings contributions over the last several years. We cannot predict future contributions from bulk power marketing and trading activities. Fuel and purchased power costs are impacted by our electricity sales volumes, existing contracts for generation fuel and purchased power, our power plant performance, prevailing market prices, and our hedging program for managing such costs. Utility operations and maintenance expenses are expected to be affected by sales mix and volumes, inflation, and other factors. Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property and changes in regulatory asset amortization. See Note 5 for the regulatory asset amortization that is being recorded in 1999 through 2004 pursuant to the Settlement Agreement. See Note 1 of Notes to Consolidated Financial Statements in the 1999 10-K regarding current depreciation rates. 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. We expect property taxes to grow primarily due to our additions to existing facilities. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. Our financial results may be affected by a number of broad factors. See "Forward-Looking Statements" for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate. -23- COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See Note 5 for a discussion of regulatory accounting. See Note 6 for a discussion of a Settlement Agreement related to the implementation of retail electric competition and to Arizona and federal legal and regulatory developments. RATE MATTERS See Note 6 for a discussion of a price reduction effective as of July 1, 2000, and for a discussion of a Settlement Agreement that will, among other things, result in five annual price reductions over a four-year period ending July 1, 2003. FORWARD-LOOKING STATEMENTS The above discussion contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax, and environmental legislation; our ability to successfully compete outside traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; the successful completion of large-scale construction projects; and successfully managing market risks. These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes we currently expect or seek. -24- ITEM 3. MARKET RISKS Our operations include managing market risks related to changes in commodity prices, interest rates, and investments held by the nuclear decommissioning trust fund. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. We employ established procedures to manage our risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into these derivative transactions to hedge purchases and sales of electricity, fuels and emissions allowances/credits. In addition, we engage in trading activities intended to profit from favorable movements of market prices. As of September 30, 2000, a hypothetical adverse price movement of 10% in the market price of our commodity derivative portfolio would decrease the fair market value of these contracts by approximately $37 million. This analysis does not include the favorable impact this same hypothetical price move would have on the underlying physical exposures being hedged with the commodity derivative portfolio. We plan to move our wholesale power marketing and trading activities to the parent company by the end of 2000. We are exposed to credit losses in the event of non-performance or non-payment by counterparties. We use a credit management process to assess and monitor the financial exposure of counterparties. Despite the fact that the great majority of our 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. Changing interest rates will affect interest paid on variable-rate debt and interest earned by the nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The nuclear decommissioning fund also has risks associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in regulated electricity prices. -25- 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. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See Note 6 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of competition and the rules regarding the introduction of retail electric competition in Arizona and a settlement agreement with the ACC. ENVIRONMENTAL MATTERS Purported Navajo Environmental Regulation As previously reported, on June 29, 2000, at the request of the Court, we filed a motion to dismiss Four Corners from a Petition for Review of EPA's regulations on the grounds that the impact of the regulations on pre-existing binding agreements was not "ripe" for judicial resolution based on EPA's issuance of an official notice indicating that it had not yet determined whether the pre-existing binding agreements with Four Corners and NGS were abrogated by the Clean Air Act. See "Environmental Matters--Purported Navajo Environmental Regulation" in Part II, Item 5 of the June 10-Q. The Court recently dismissed Four Corners on the above-mentioned grounds. WATER SUPPLY As previously reported, we and other parties petitioned the U.S. Supreme Court for review of an Arizona Supreme Court decision regarding groundwater rights, and an issue important to the claims to water in the Lower Gila River Watershed in Arizona was pending on appeal before the Arizona Supreme Court. See "Environmental Matters - Water Supply" in Part I - Item 1 of the 1999 10-K. The U.S. Supreme Court denied the petition. In addition, the Arizona Supreme Court issued a decision affirming the lower court's definition of groundwater. We and other parties have filed a motion for reconsideration on one aspect of that decision. PURCHASED POWER AGREEMENTS As previously reported, in July 2000 we became involved in a dispute with PacifiCorp relating to certain provisions of the Long-Term Power Transaction Agreement dated September 1990. See "Purchased Power Agreements" in Part II, Item 5 of the June 10-Q. We and PacifiCorp have settled the issues related to the dispute. The resolution of this matter will not have a material adverse impact on our financial position or results of operations. -26- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit No. Description ----------- ----------- 27.1 Financial Data Schedule In addition to those Exhibits shown above, 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:
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE ----------- ----------- ---------------------------- ----------- -------------- 10.1 Articles of Incorporation 4.2 to Form S-3 Registration 1-4473 9-29-93 restated as of May 25, 1988 Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report 10.2 Bylaws, amended as of 3.1 to 1995 Form 10-K Report 1-4473 3-29-96 February 20, 1996 10.3 Addendum to Settlement Agreement 10.1 to Pinnacle West September 1-8962 11-14-00 2000 10-Q
(b) Reports on Form 8-K During the quarter ended September 30, 2000, and the period from October 1 through November 14, 2000, we filed the following reports on Form 8-K: Report dated July 12, 2000, relating to a preliminary ruling issued by a Maricopa County Superior Court judge on cross-motions for summary judgment in connection with lawsuits filed relating to the adoption or amendment of the retail electric competition rules. Report dated August 2, 2000 comprised of Exhibits to the Company's Registration Statements (Registration Nos. 333-58445 and 333-94277) relating to the Company's offering of $300 million of Notes. ---------- (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. -27- SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated: November 14, 2000 By: Michael V. Palmeri ------------------------------------ Michael V. Palmeri Vice President, Finance (Principal Accounting Officer and Officer Duly Authorized to sign this Report)