10-Q 1 0001.txt QUARTERLY REPORT FOR QTR ENDING 6-30-2000 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 June 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 August 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 Company - Arizona Public Service Company DOE - United States Department of Energy 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 FERC - United States Federal Energy Regulatory Commission Four Corners - Four Corners Power Plant ITC - Investment tax credit 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 Settlement Agreement - APS' Settlement Agreement approved by the ACC in 1999 Palo Verde - Palo Verde Nuclear Generating Station Pinnacle West - Pinnacle West Capital Corporation 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 -2- PART I - FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited) Three Months Ended June 30, ---------------------- 2000 1999 --------- --------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .......................... $ 719,394 $ 511,434 --------- --------- FUEL EXPENSES: Fuel for electric generation ....................... 73,808 58,283 Purchased power .................................... 215,095 76,473 --------- --------- Total ........................................... 288,903 134,756 --------- --------- OPERATING REVENUES LESS FUEL EXPENSES ................ 430,491 376,678 --------- --------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses . 104,583 106,434 Depreciation and amortization ...................... 96,526 96,533 Income taxes ....................................... 71,441 49,856 Other taxes ........................................ 25,596 25,352 --------- --------- Total ........................................... 298,146 278,175 --------- --------- OPERATING INCOME ..................................... 132,345 98,503 --------- --------- OTHER INCOME (DEDUCTIONS): Other - net ........................................ (1,940) (1,485) Income taxes ....................................... 801 7,227 --------- --------- Total ........................................... (1,139) 5,742 --------- --------- INCOME BEFORE INTEREST DEDUCTIONS .................... 131,206 104,245 --------- --------- INTEREST DEDUCTIONS: Interest on long-term debt ......................... 32,607 33,868 Interest on short-term borrowings .................. 3,853 1,936 Debt discount, premium and expense ................. 1,575 1,912 Capitalized interest ............................... (2,680) (3,013) --------- --------- Total ........................................... 35,355 34,703 --------- --------- EARNINGS FOR COMMON STOCK ............................ $ 95,851 $ 69,542 ========= ========= See Notes to Condensed Financial Statements. -3- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited) Six Months Ended June 30, ------------------------ 2000 1999 ----------- --------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES ........................ $ 1,165,375 $ 925,417 ----------- --------- FUEL EXPENSES: Fuel for electric generation ..................... 132,619 110,399 Purchased power .................................. 282,048 124,703 ----------- --------- Total ......................................... 414,667 235,102 ----------- --------- OPERATING REVENUES LESS FUEL EXPENSES .............. 750,708 690,315 ----------- --------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses 213,111 206,696 Depreciation and amortization .................... 192,473 192,672 Income taxes ..................................... 95,708 74,659 Other taxes ...................................... 50,977 50,829 ----------- --------- Total ......................................... 552,269 524,856 ----------- --------- OPERATING INCOME ................................... 198,439 165,459 ----------- --------- OTHER INCOME (DEDUCTIONS): Other - net ...................................... (312) (4,419) Income taxes ..................................... 126 11,482 ----------- --------- Total ......................................... (186) 7,063 ----------- --------- INCOME BEFORE INTEREST DEDUCTIONS .................. 198,253 172,522 ----------- --------- INTEREST DEDUCTIONS: Interest on long-term debt ....................... 65,945 67,424 Interest on short-term borrowings ................ 5,120 4,004 Debt discount, premium and expense ............... 3,468 3,757 Capitalized interest ............................. (4,906) (5,999) ----------- --------- Total ......................................... 69,627 69,186 ----------- --------- NET INCOME ......................................... 128,626 103,336 PREFERRED STOCK DIVIDEND REQUIREMENTS .............. -- 1,016 ----------- --------- EARNINGS FOR COMMON STOCK .......................... $ 128,626 $ 102,320 =========== ========= See Notes to Condensed Financial Statements -4- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Twelve Months Ended June 30, --------------------------- 2000 1999 ----------- ----------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .................... $ 2,532,755 $ 2,109,677 ----------- ----------- FUEL EXPENSES: Fuel for electric generation ................. 266,069 241,604 Purchased power .............................. 708,991 366,155 ----------- ----------- Total ..................................... 975,060 607,759 ----------- ----------- OPERATING REVENUES LESS FUEL EXPENSES .......... 1,557,695 1,501,918 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses..................................... 444,156 423,452 Depreciation and amortization ................ 381,858 384,433 Income taxes ................................. 213,064 202,469 Other taxes .................................. 96,714 100,134 ----------- ----------- Total ..................................... 1,135,792 1,110,488 ----------- ----------- OPERATING INCOME ............................... 421,903 391,430 ----------- ----------- OTHER INCOME (DEDUCTIONS): Other - net .................................. (7,430) (11,807) Income taxes ................................. 21,171 32,291 ----------- ----------- Total ..................................... 13,741 20,484 ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS .............. 435,644 411,914 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt ................... 131,197 135,295 Interest on short-term borrowings ............ 9,388 8,425 Debt discount, premium and expense ........... 7,034 7,470 Capitalized interest ......................... (5,586) (13,741) ----------- ----------- Total ..................................... 142,033 137,449 ----------- ----------- INCOME BEFORE EXTRAORDINARY CHARGE ............. 293,611 274,465 Extraordinary charge - net of income taxes of $94,115............................. 139,885 -- ----------- ----------- NET INCOME ..................................... 153,726 274,465 PREFERRED STOCK DIVIDEND REQUIREMENTS .......... -- 5,406 ----------- ----------- EARNINGS FOR COMMON STOCK ...................... $ 153,726 $ 269,059 =========== ===========
See Notes to Condensed Financial Statements -5- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ASSETS (Unaudited) June 30, December 31, 2000 1999 ----------- ----------- (Thousands of Dollars) UTILITY PLANT: Electric plant in service and held for future use ................................ $ 7,671,230 $ 7,545,575 Less accumulated depreciation and amortization .............................. 3,139,302 3,026,041 ----------- ----------- Total ................................... 4,531,928 4,519,534 Construction work in progress .............. 195,770 184,764 Nuclear fuel, net of amortization .......... 47,864 49,114 ----------- ----------- Utility plant - net ..................... 4,775,562 4,753,412 ----------- ----------- INVESTMENTS AND OTHER ASSETS ................. 230,950 208,457 ----------- ----------- CURRENT ASSETS: Cash and cash equivalents .................. 8,172 7,477 Accounts receivable: Service customers ....................... 307,572 201,704 Other ................................... 57,822 35,684 Allowance for doubtful accounts ......... (1,566) (1,538) Accrued utility revenues ................... 112,261 72,919 Materials and supplies, at average cost .... 73,038 69,977 Fossil fuel, at average cost ............... 18,727 21,869 Deferred income taxes ...................... 8,163 8,163 Other ...................................... 40,096 30,885 ----------- ----------- Total current assets .................... 624,285 447,140 ----------- ----------- DEFERRED DEBITS: Regulatory assets .......................... 545,622 613,729 Unamortized debt issue costs ............... 11,664 15,172 Other ...................................... 75,760 79,714 ----------- ----------- Total deferred debits ................... 633,046 708,615 ----------- ----------- TOTAL ................................... $ 6,263,843 $ 6,117,624 =========== =========== See Notes to Condensed Financial Statements. -6- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS LIABILITIES (Unaudited) June 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 ................................. 559,333 558,208 ---------- ---------- Common stock equity ............................ 1,984,299 1,983,174 Long-term debt less current maturities ............ 1,756,388 1,997,400 ---------- ---------- Total capitalization ........................... 3,740,687 3,980,574 ---------- ---------- CURRENT LIABILITIES: Commercial paper .................................. 200,875 38,300 Current maturities of long-term debt .............. 114,886 114,711 Accounts payable .................................. 222,977 170,662 Accrued taxes ..................................... 189,552 62,858 Accrued interest .................................. 31,361 32,299 Common dividends payable .......................... 85,000 -- Customer deposits ................................. 25,016 24,682 Other ............................................. 34,095 26,248 ---------- ---------- Total current liabilities ...................... 903,762 469,760 ---------- ---------- DEFERRED CREDITS AND OTHER: Deferred income taxes ............................. 1,143,153 1,178,085 Unamortized gain - sale of utility plant .......... 70,924 73,212 Customer advances for construction ................ 40,409 38,150 Other ............................................. 364,908 377,843 ---------- ---------- Total deferred credits and other ............... 1,619,394 1,667,290 ---------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 9) TOTAL .......................................... $6,263,843 $6,117,624 ========== ========== See Notes to Condensed Financial Statements. -7- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited) Six Months Ended June 30, --------------------- 2000 1999 --------- --------- (Thousands of Dollars) CASH FLOWS FROM OPERATING ACTIVITIES: Net income ............................................ $ 128,626 $ 103,336 Items not requiring cash: Depreciation and amortization ....................... 192,473 192,672 Nuclear fuel amortization ........................... 15,124 15,673 Deferred income taxes - net ......................... (22,609) (21,445) Changes in certain current assets and liabilities: Accounts receivable - net ........................... (127,978) 32,376 Accrued utility revenues ............................ (39,342) (30,306) Materials, supplies and fossil fuel ................. 81 (5,653) Other current assets ................................ (9,211) (3,952) Accounts payable .................................... 56,919 (17,952) Accrued taxes ....................................... 126,694 89,322 Accrued interest .................................... (938) 991 Other current liabilities ........................... 8,181 (2,416) Other - net ........................................... (7,979) (19,457) --------- --------- Net cash flow provided by operating activities.... 320,041 333,189 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures .................................. (189,401) (153,730) Capitalized interest .................................. (4,906) (5,999) Other ................................................. (3,114) 1,172 --------- --------- Net cash flow used for investing activities ...... (197,421) (158,557) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Long-term debt ........................................ -- 142,952 Short-term borrowings - net ........................... 162,575 45,120 Dividends paid on common stock ........................ (42,500) (42,500) Dividends paid on preferred stock ..................... -- (1,393) Repayment of preferred stock .......................... -- (96,499) Repayment and reacquisition of long-term debt ......... (242,000) (216,184) --------- --------- Net cash flow used for financing activities...... (121,925) (168,504) --------- --------- Net increase in cash and cash equivalents .............. 695 6,128 Cash and cash equivalents at beginning of period ....... 7,477 5,558 --------- --------- Cash and cash equivalents at end of period ............. $ 8,172 $ 11,686 ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the period for: Interest (excluding capitalized interest) .......... $ 64,470 $ 64,233 Income taxes ....................................... $ -- $ 7,849 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 six months ended June 30, 2000. 5. Regulatory Accounting For regulated operations, we prepare our financial statements in accordance with Statement of Financial Accounting Standards (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 Financial Accounting Standards Board (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 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. The regulatory assets to be recovered under the 1999 Settlement Agreement are now being amortized as follows (millions of dollars): -9- 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): June 30, December 31, 2000 1999 ----------- ----------- Electric plant in service & held for future use $ 3,761,855 $ 3,770,234 Accumulated depreciation and amortization (1,678,752) (1,641,855) Construction work in progress 85,220 67,306 Nuclear fuel, net of amortization 47,864 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. The following are the major provisions of the Settlement Agreement, as approved: * We will reduce rates for standard offer service for customers with loads less than 3 megawatts 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 annually ($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 3 megawatts or greater, standard offer rates will be reduced in varying annual increments that total 5% through 2002. -10- * 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 megawatts 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 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 that 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. 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 -11- 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 and the adoption or amendment of the Rules, but two related cases filed by other utilities have been partially decided in a manner adverse to those utilities' positions. On July 12, 2000, a Maricopa County Superior Court judge issued a preliminary ruling in favor of the ACC and denied substantive challenges to the Rules that had been made by the electric cooperatives. However, he concluded that some of the Rules were invalid because of procedural deficiencies. Specifically, the judge concluded that several non-ratemaking Rules were required to be presented to the Arizona Attorney General for certification. Additionally, the judge determined that the Arizona Constitution requires the ACC to make findings regarding the fair value of property in Arizona of competitive electric service providers. We do not believe that the ruling 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 fair value of our property in the order approving our Settlement Agreement. The ruling does not immediately affect the Rules. We expect that, in the next few weeks, the court will consider proposed forms of judgment which will establish the specific impact of the ruling. Although the ACC has not yet indicated what steps it intends to take after a judgment is issued, the ACC could appeal the ruling to the Court of Appeals or could elect to take corrective action to correct the procedural deficiencies identified in the judge's ruling. The cooperatives may also appeal the ruling. There is authority indicating that if the order is appealed by the ACC, it will be automatically stayed pending further judicial review. Certain other appeals of the Rules are still pending in the Maricopa County Superior Court. We believe that the court may rule on the remaining appeals later this year or next year. On January 14, 2000, a special action was filed requesting the Arizona Supreme Court to enjoin implementation of the Rules and decide whether the ACC can allow the competitive marketplace, rather than the ACC, to set just and reasonable rates under the Arizona Constitution. The issue of competitively set rates has been decided by lower Arizona courts in favor of the ACC in four separate lawsuits, two of which relate to telecommunications companies. The Supreme Court denied to hear the case as a special action on March 17, 2000. The lower court litigation will continue. 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 -12- 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 megawatts 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 megawatt 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 megawatt requirement. * When effective, residential customers will be 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 competitive generation assets and services to affiliates no later than December 31, 2002. 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. -13- 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 megawatt (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 us to compete in the new regulatory environment. 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 -14- 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. 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). We plan to move our wholesale power marketing and trading activities to Pinnacle West by the end of 2000. Eliminations primarily relate to intersegment sales of electricity. Segment information for the three, six and twelve months ended June 30, 2000 and 1999 is as follows (millions of dollars):
3 Months Ended 6 Months Ended 12 Months Ended June 30, June 30, June 30, --------------- ----------------- ------------------- 2000 1999 2000 1999 2000 1999 ----- ----- ------- ----- ------- ------- Operating Revenues: Delivery $ 719 $ 511 $ 1,165 $ 925 $ 2,533 $ 2,110 Generation 249 220 428 396 886 877 Eliminations (249) (220) (428) (396) (886) (877) ----- ----- ------- ----- ------- ------- Total $ 719 $ 511 $ 1,165 $ 925 $ 2,533 $ 2,110 ===== ===== ======= ===== ======= ======= Earnings excluding Extraordinary Charge: Delivery $ 55 $ 34 $ 80 $ 55 $ 172 $ 144 Generation 41 36 49 47 122 125 ----- ----- ------- ----- ------- ------- Total $ 96 $ 70 $ 129 $ 102 $ 294 $ 269 ===== ===== ======= ===== ======= ======= As of June 30, As of December 31, 2000 1999 ------ ------ Assets: Delivery $3,938 $3,796 Generation 2,326 2,322 ------ ------ Total $6,264 $6,118 ====== ======
9. Accounting Matters In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, which is effective for us in 2001. SFAS No. 133 requires that entities recognize all derivatives as either assets or -15- liabilities on the balance sheet and measure those instruments at fair value. The standard also provides specific guidance for accounting for derivatives designated as hedging instruments. We are currently evaluating what impact this standard will have on our financial statements. -16- 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. 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. These Notes add further details to the discussion. OPERATING RESULTS The following table summarizes our revenues and earnings for the three-month, six-month and twelve-month periods ended June 30, 2000 and 1999: Periods ended June 30 (Unaudited) (Thousands of Dollars)
Three Months Six Months Twelve Months ------------------- -------------------- ------------------------- 2000 1999 2000 1999 2000 1999 -------- -------- ---------- -------- ---------- ---------- Operating Revenues $719,394 $511,434 $1,165,375 $925,417 $2,532,755 $2,109,677 Earnings for Common Stock $ 95,851 $ 69,542 $ 128,626 $102,320 $ 153,726(1) $ 269,059
(1) The twelve months ended June 30, 2000 includes an extraordinary charge of $139,885 net of income taxes of $94,115. OPERATING RESULTS - THREE-MONTH PERIOD ENDED JUNE 30, 2000 COMPARED WITH THREE-MONTH PERIOD ENDED JUNE 30, 1999 Earnings for the three months ended June 30, 2000 were $96 million compared with $70 million for the same period in the prior year. Earnings increased for the three-month period -17- primarily because of an increase in the profitability of wholesale power marketing and trading activities and increases 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 effects of increased fuel and purchased power costs, the completion of the amortization of ITCs in 1999, and an electricity price reduction. See Note 6 for information on the price reduction. See "Income Taxes" below for a discussion of the ITC amortization. Electric operating revenues increased $208 million because of: * increased power marketing and trading revenues ($150 million) * increases in the number of customers and the average amount of electricity used by customers ($44 million) * warmer weather impacts ($18 million) and * miscellaneous factors ($3 million). As mentioned above, these positive factors were partially offset by the effect of a reduction in retail electricity prices ($7 million). The increase in power marketing and trading 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 $105 million. Fuel and purchased power expenses were also higher because of higher retail sales volumes and increased fuel prices. OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 2000 COMPARED WITH SIX-MONTH PERIOD ENDED JUNE 30, 1999 Earnings for the six months ended June 30, 2000 were $129 million compared with $102 million for the same period in the prior year. The increase primarily relates to an increase in the profitability of wholesale power marketing and trading activities, and increases 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 effects of increased fuel and purchased power costs, the completion of the amortization of ITCs in 1999, an electricity price reduction, and higher utility operations and maintenance expense. See Note 6 for information on the price reduction. See "Income Taxes" below for a discussion of the ITC amortization. Electric operating revenues increased $240 million because of: * increased power marketing and trading revenues ($173 million) * increases in the number of customers and the average amount of electricity used by customers ($55 million) * warmer weather impacts ($19 million) and * miscellaneous factors ($6 million). These positive factors were partially offset by the effect of a reduction in retail electricity prices ($13 million). -18- The increase in power marketing and trading 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 $129 million. Fuel and purchased power expenses were also higher because of higher retail sales volumes and increased fuel prices. Utility operations and maintenance expenses increased primarily because of higher costs related to customer growth. OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 2000 COMPARED WITH TWELVE-MONTH PERIOD ENDED JUNE 30, 1999 Earnings for the twelve months ended June 30, 2000 were $154 million compared with $269 million for the same period in the prior year. The decrease primarily relates to an extraordinary charge recorded in the third quarter of 1999, partially offset by higher income excluding the extraordinary charge. 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 $25 million over the comparable prior period primarily because of increases in the number of customers and in the average amount of electricity used by customers, and an increase in the profitability of wholesale power marketing and trading activities. These positive factors more than offset decreases due to a reduction in retail electricity prices, higher utility operations and maintenance expense, and the completion of the amortization of ITCs in 1999. See Note 6 for information on the price reduction. See "Income Taxes" below for a discussion of the ITC amortization. Electric operating revenues increased $423 million because of: * increased power marketing and trading revenues ($338 million) * increases in the number of customers and the average amount of electricity used by customers ($94 million) and * miscellaneous factors ($18 million). These positive factors were partially offset by the effect of a reduction in retail prices ($27 million). The increase in power marketing and trading 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 $306 million. Fuel and purchased power expenses were also higher because of higher retail sales volumes and increased fuel prices. Utility operations and maintenance expenses increased primarily because of $16 million of non-recurring items recorded in the current twelve-month period, including a provision for -19- certain environmental costs. Other increases primarily related to customer growth, power marketing costs, and technology related costs. 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 six months ended June 30, 2000, we incurred approximately $181 million in capital expenditures, which is approximately 48% of the most recently estimated 2000 capital expenditures. Our projected capital expenditures for the next three years are $380 million in 2000; $395 million in 2001; and $373 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 six months ended June 30, 2000, we redeemed approximately $242 million of our long-term debt with cash from operations and short-term borrowings. On August 7, 2000, we issued $300 million of our 7-5/8% Notes Due 2005. In 2001 we will purchase Units 1, 2 and 3 of the West Phoenix Power Plant at the expiration of its lease term. 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. 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; -20- 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; successfully managing market risks; and technological developments in the electric industry. 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. 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 June 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 $53 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 Pinnacle West 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. -21- 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 EPA Environmental Regulation - Clean Air Act As previously reported, EPA's final National Ambient Air Quality Standards for ozone and particulate matter were challenged, and the court determined that EPA's promulgation of the standards violated the constitutional prohibition on delegation of legislative power. See "Environmental Matters--EPA Environmental Regulation--Clean Air Act" in Part I, Item 1 of the 1999 10-K. The court remanded the ozone and fine particulate standards and vacated the coarse particulate matter standard. The U.S. Supreme Court recently agreed to review these decisions. We cannot currently predict the outcome of this matter. Purported Navajo Environmental Regulation In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. We believe that the regulations do not recognize that the Tribe did not intend to assert jurisdiction over Four Corners and NGS. On July 12, 2000, the Four Corners participants and the NGS participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. We cannot currently predict the outcome of this matter. As previously reported, in April 1999, we filed a Petition for Review of EPA's regulations regarding issuing Federal operating permits to cover stationary sources on Indian reservations. See "Environmental Matters--Purported Navajo Environmental Regulation" in Part I, Item 1 of the 1999 10-K. On June 29, 2000, at the request of the Court, we filed a motion to dismiss Four Corners from this petition 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. -22- WATER SUPPLY As previously reported, we and other parties petitioned the U.S. Supreme Court for review of the decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. See "Water Supply" in Item I, Part 1 of the 1999 10-K. This petition was denied, and the pending lower court litigation will continue. PURCHASED POWER AGREEMENTS As previously reported, in September 1990, we entered into a thirty year agreement under which we and Pacificorp engage in a one-for-one seasonal capacity exchange. We are entitled to receive up to 480 MW of capacity from PacifiCorp during our summer peak season (through September 15). See "Generating Fuel and Purchased Power - Purchased Power Agreements" in Part I, Item 1 of the 1999 10-K. There is currently a dispute under the Long-Term Power Transaction Agreement (the "Agreement") relating to the value of power delivered to PacifiCorp under the Supplemental Energy provisions of the Agreement. As a result of the dispute, we understand that PacificCorp believes it is owed monies by us and, since August 8, 2000, has been withholding power due to us under the terms of Agreement. We believe PacificCorp is in breach of the Agreement, and the breach has been and is resulting in damage claims against PacifiCorp which are accruing daily in an amount dependent upon daily energy cost rates. The parties are currently attempting to resolve the dispute and no litigation or arbitration has been commenced. -23- 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 Amendment No. 14 to the 10.4 to the Pinnacle West 1-8962 8-14-00 ANPP Participation June 30, 2000 Form Agreement 10-Q Report 10.4 Pinnacle West Capital 99.2 to Pinnacle West's 1-8962 7-3-00 Corporation and Arizona Registration Statement on Public Service Company Form S-8 No. 333-40796 Directors' Retirement Plan (as Amended and Restated)
(b) Reports on Form 8-K During the quarter ended June 30, 2000, and the period from July 1 through August 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. -24- SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated: August 14, 2000 By: Michael V. Palmeri ------------------------------------ Michael V. Palmeri Vice President, Finance (Principal Accounting Officer and Officer Duly Authorized to sign this Report)