Securities and Exchange Commission Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2001 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 1-8962 PINNACLE WEST CAPITAL CORPORATION (Exact name of registrant as specified in its charter) Arizona 86-0512431 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 400 North Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (602) 250-1000 (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate 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, no par value, outstanding as of May 11, 2001: 84,733,461
Glossary ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission APS - Arizona Public Service Company, a subsidiary of the Company APS Energy Services - APS Energy Services Company, Inc., a subsidiary of the Company CC&N - Certificate of Convenience and Necessity Citizens - Citizens Communications Company Company - Pinnacle West Capital Corporation DIG - Derivatives Implementation Group EITF - Emerging Issues Task Force El Dorado - El Dorado Investment Company, a subsidiary of the Company ERMC - Energy Risk Management Committee FASB - Financial Accounting Standards Board FERC - United States Federal Energy Regulatory Commission Four Corners - Four Corners Power Plant ISO - California Independent System Operator ITC -investment tax credit KW - kilowatt, one thousand watts KWh -kilowatt-hour, one thousand watts per hour MW - megawatt, one million watts MWh - megawatt-hour, one million watts per hour 1999 Settlement Agreement - comprehensive settlement agreement related to the implementation of retail electric competition NPC - Nevada Power Company NPUC - Nevada Public Utility Commission Palo Verde - Palo Verde Nuclear Generating Station PG&E - PG&E Corp. Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of the Company PX - California Power Exchange Rules - ACC retail electric competition rules Salt River Project - Salt River Project Agricultural Improvement and Power District SCE - Southern California Edison SFAS - Statement of Financial Accounting Standards SunCor - SunCor Development Company, a subsidiary of the Company 2000 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the fiscal year ended December 31, 2000
-2- PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS. PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (unaudited) (dollars in thousands, except per share amounts) <TABLE> <CAPTION> Three Months Ended March 31, -------------------------- 2001 2000 --------- --------- <S> <C> <C> Operating Revenues Electric $ 906,494 $ 446,228 Real estate 32,335 41,889 --------- --------- Total 938,829 488,117 --------- --------- Operating Expenses Fuel and purchased power 516,424 125,432 Operations and maintenance 125,250 110,449 Real estate operations 31,008 32,820 Depreciation and amortization 104,781 102,566 Taxes other than income taxes 25,303 25,392 --------- --------- Total 802,766 396,659 --------- --------- Operating Income 136,063 91,458 Other Income (Expense) (738) 35,600 --------- --------- Income Before Interest, Income Taxes and Accounting Change 135,325 127,058 --------- --------- Interest Expense Interest charges 42,749 39,499 Capitalized interest (10,427) (3,849) --------- --------- Total 32,322 35,650 --------- --------- Income Before Income Taxes and Accounting Change 103,003 91,408 Income Taxes 40,798 37,338 --------- --------- Income Before Accounting Change 62,205 54,070 Cumulative Effect of a Change in Accounting for Derivatives - Net of Income Tax Benefit of $1,793 (2,755) -- --------- --------- Net Income $ 59,450 $ 54,070 ========= ========= Average Common Shares Outstanding - Basic 84,727 84,728 Average Common Shares Outstanding - Diluted 84,966 84,834 Earnings Per Average Common Share Outstanding Income Before Accounting Change - Basic $ 0.73 $ 0.64 Net Income - Basic 0.70 0.64 Income Before Accounting Change - Diluted 0.73 0.64 Net Income - Diluted 0.70 0.64 Dividends Declared Per Share $ 0.375 $ 0.35 </TABLE> See Notes to Condensed Consolidated Financial Statements.
-3- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (unaudited) (dollars in thousands, except per share amounts) <TABLE> <CAPTION> Twelve Months Ended March 31, ----------------------------- 2001 2000 ----------- ----------- <S> <C> <C> Operating Revenues Electric $ 3,992,076 $ 2,325,429 Real estate 148,811 147,525 ----------- ----------- Total 4,140,887 2,472,954 ----------- ----------- Operating Expenses Fuel and purchased power 2,323,784 819,569 Operations and maintenance 465,006 454,831 Real estate operations 132,610 130,101 Depreciation and amortization 433,884 420,919 Taxes other than income taxes 99,691 96,513 ----------- ----------- Total 3,454,975 1,921,933 ----------- ----------- Operating Income 685,912 551,021 Other Income (Expense) (36,304) 48,895 ----------- ----------- Income From Continuing Operations Before Interest and Income Taxes 649,608 599,916 ----------- ----------- Interest Expense Interest charges 169,697 157,183 Capitalized interest (28,216) (11,439) ----------- ----------- Total 141,481 145,744 ----------- ----------- Income From Continuing Operations Before Income Taxes 508,127 454,172 Income Taxes 197,660 161,020 ----------- ----------- Income From Continuing Operations 310,467 293,152 Income Tax Benefit From Discontinued Operations -- 38,000 Extraordinary Charge - Net of Income Taxes of $94,115 -- (139,885) Cumulative Effect of a Change in Accounting for Derivatives - Net of Income Tax Benefit of $1,793 (2,755) -- ----------- ----------- Net Income $ 307,712 $ 191,267 =========== =========== Average Common Shares Outstanding - Basic 84,732 84,732 Average Common Shares Outstanding - Diluted 84,974 84,925 Earnings Per Average Common Share Outstanding Continuing Operations - Basic $ 3.66 $ 3.46 Net Income - Basic 3.63 2.26 Continuing Operations - Diluted 3.65 3.45 Net Income - Diluted 3.62 2.25 Dividends Declared Per Share $ 1.45 $ 1.350 </TABLE> See Notes to Condensed Consolidated Financial Statements.
-4- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS (dollars in thousands) March 31, December 31, 2001 2000 ---------- ---------- (unaudited) Current Assets Cash and cash equivalents $ 249,393 $ 10,363 Customer and other receivables--net 429,107 513,822 Accrued utility revenues 61,600 74,566 Materials and supplies 75,523 71,966 Fossil fuel 19,976 19,405 Deferred income taxes 5,793 5,793 Assets from risk management activities 168,562 17,506 Other current assets 62,957 80,492 ---------- ---------- Total current assets 1,072,911 793,913 ---------- ---------- Investments and Other Assets Real estate investments--net 388,070 371,323 Other assets 362,987 318,249 ---------- ---------- Total investments and other assets 751,057 689,572 ---------- ---------- Property, Plant and Equipment Plant in service and held for future use 7,885,592 7,809,566 Less accumulated depreciation and amortization 3,239,179 3,188,302 ---------- ---------- Total 4,646,413 4,621,264 Construction work in progress 562,072 464,540 Nuclear fuel, net of amortization 51,686 47,389 ---------- ---------- Net property, plant and equipment 5,260,171 5,133,193 ---------- ---------- Deferred Debits Regulatory assets 436,474 469,867 Other deferred debits 75,317 62,606 ---------- ---------- Total deferred debits 511,791 532,473 ---------- ---------- Total Assets $7,595,930 $7,149,151 ========== ========== See Notes to Condensed Consolidated Financial Statements.
-5- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND EQUITY (dollars in thousands) March 31, December 31, 2001 2000 ---------- ---------- (unaudited) Current Liabilities Accounts payable $ 326,387 $ 375,805 Accrued taxes 145,813 89,246 Accrued interest 14,021 42,954 Short-term borrowings 178,625 82,775 Current maturities of long-term debt 496,266 463,469 Customer deposits 27,080 26,189 Liabilities from risk management activities 81,297 37,179 Other current liabilities 94,936 73,681 ---------- ---------- Total current liabilities 1,364,425 1,191,298 ---------- ---------- Long-Term Debt Less Current Maturities 2,125,239 1,955,083 ---------- ---------- Deferred Credits and Other Deferred income taxes 1,159,350 1,143,040 Unamortized gain - sale of utility plant 67,492 68,636 Other 433,561 408,380 ---------- ---------- Total deferred credits and other 1,660,403 1,620,056 ---------- ---------- Commitments and contingencies (Notes 6, 7, 9 and 11) Common Stock Equity Common stock, no par value 1,530,891 1,532,831 Accumulated other comprehensive income 37,425 -- Retained earnings 877,547 849,883 ---------- ---------- Total common stock equity 2,445,863 2,382,714 ---------- ---------- Total Liabilities and Equity $7,595,930 $7,149,151 ========== ========== See Notes to Condensed Consolidated Financial Statements.
-6- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited) (dollars in thousands) Three Months Ended March 31, -------------------------- 2001 2000 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Income before accounting change $ 62,205 $ 54,070 Items not requiring cash Depreciation and amortization 104,781 102,566 Nuclear fuel amortization 7,581 7,931 Deferred income taxes--net (6,250) (9,398) Other--net 23 53 Changes in current assets and liabilities Customer and other receivables--net 69,118 48,180 Accrued utility revenues 12,966 9,826 Materials, supplies and fossil fuel (4,128) (3,193) Other current assets 20,790 (3,160) Accounts payable (50,899) (53,023) Accrued taxes 56,567 62,522 Accrued interest (28,933) (13,542) Risk management activities - net (99,504) (5,658) Other current liabilities 37,795 7,782 Change in El Dorado partnership investment 46 (32,072) Increase in land held for sale (19,789) (2,097) Other--net 26,840 22,505 --------- --------- Net Cash Flow Provided By Operating Activities 189,209 193,292 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (189,924) (89,704) Capitalized interest (10,427) (3,849) Other--net (14,747) (2,461) --------- --------- Net Cash Flow Used For Investing Activities (215,098) (96,014) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 387,000 49,000 Short-term borrowings--net 95,850 90,500 Dividends paid on common stock (31,785) (29,654) Repayment of long-term debt (184,206) (100,295) Other--net (1,940) (230) --------- --------- Net Cash Flow Provided by Financing Activities 264,919 9,321 --------- --------- Net Cash Flow 239,030 106,599 Cash and Cash Equivalents at Beginning of Period 10,363 20,705 --------- --------- Cash and Cash Equivalents at End of Period $ 249,393 $ 127,304 ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest, net of amounts capitalized $ 57,839 $ 34,618 Income taxes $ 16,077 $ -- See Notes to Condensed Consolidated Financial Statements.
-7- PINNACLE WEST CAPITAL CORPORATION NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 1. The condensed consolidated financial statements include the accounts of Pinnacle West and its subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor, and El Dorado. All significant intercompany accounts and transactions have been eliminated. We have reclassified certain prior year amounts to conform to the current year presentation. 2. Our unaudited condensed consolidated financial statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature with the exception of the cumulative effect of a change in accounting for derivatives (see Note 9), the extraordinary charge (see Note 5) and the tax benefit from discontinued operations (see Note 12). We suggest that these Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements be read along with the Consolidated Financial Statements and Notes to Consolidated Financial Statements included in our 2000 10-K. 3. Weather conditions and wholesale power marketing activities can have significant impacts on our results for interim periods. Results for interim periods do not necessarily represent results to be expected for the year. 4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the three months ended March 31, 2001. 5. Regulatory Accounting APS is regulated by the ACC and the FERC. The accompanying financial statements reflect the ratemaking policies of these commissions. 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 EITF of the FASB issued EITF 97-4. EITF 97-4 which 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 1999 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. As a result, we tested the generation assets for impairment and determined that the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, 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 1999 Settlement Agreement, under the 1996 regulatory
-8- agreement (see Note 6), the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are now being amortized through June 30, 2004 as follows (dollars in millions): 1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $86 $18 $686 The majority of our remaining regulatory assets relate to deferred income taxes and rate synchronization cost deferrals. The consolidated balance sheets include the amounts listed below for generation assets not subject to SFAS No. 71 (for additional generation information see Note 8): (dollars in thousands) March 31, December 31, 2001 2000 ----------- ----------- Electric plant in service and held for future use $ 3,862,127 $ 3,856,600 Accumulated depreciation and amortization (1,725,287) (1,693,079) Construction work in progress 400,728 304,992 Nuclear fuel, net of amortization 51,686 47,389 6. Regulatory Matters ELECTRIC INDUSTRY RESTRUCTURING STATE 1999 SETTLEMENT AGREEMENT. On May 14, 1999, APS 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 1999 Settlement Agreement, with some modifications. On December 13, 1999, two parties filed lawsuits challenging the ACC's approval of the 1999 Settlement Agreement. Each party bringing the lawsuits appealed the ACC's order approving the APS 1999 Settlement Agreement directly to the Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on December 26, 2000, the Arizona Court of Appeals affirmed the ACC's approval of the 1999 Settlement Agreement. This decision was not appealed and has become final. In the other appeal, on April 5, 2001, the Arizona Court of Appeals again affirmed the ACC's approval of the 1999 Settlement Agreement. The Arizona Consumers Council, which filed that appeal, has petitioned the Arizona Supreme Court for review of the Court of Appeals' decision. The following are the major provisions of the 1999 Settlement Agreement, as approved:
-9- * APS has reduced, and will reduce, rates for standard offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% 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 1999 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% in the years 1999 through 2002. * Unbundled rates being charged by APS for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004. * There 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 APS 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 APS' cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders. * APS 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 the "provider of last resort" and standard offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. * APS' distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the electric competition rules (see "Retail Electric Competition Rules" below), including an additional 140 MW being made available to eligible non-residential customers. APS opened its distribution system to retail access for all customers on January 1, 2001. * Prior to the 1999 Settlement Agreement, APS was recovering substantially all of its regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that APS has demonstrated that its allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value. APS will not be allowed to recover $183 million net present value of the above amounts. The 1999 Settlement Agreement provides that APS will have the opportunity to recover $350 million net present value
-10- through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery due to sales volume variances. * APS will form a separate corporate affiliate or affiliates and transfer to such affiliate(s) its generating assets and competitive services at book value as of the date of transfer, and will complete the transfer no later than December 31, 2002. Accordingly, APS plans to complete the move of such assets and services from APS to the parent company or to Pinnacle West Energy by the end of 2002, as required. APS will be allowed to defer and later collect, beginning July 1, 2004, sixty-seven percent of its costs to accomplish the required transfer of generation assets to an affiliate. * When the 1999 Settlement Agreement approved by the ACC is no longer subject to judicial review, APS will move to dismiss all of its litigation pending against the ACC as of the date APS entered into the 1999 Settlement Agreement. To protect its rights, APS has 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. Although the Rules allow retail customers to have access to competitive providers of energy and energy services (see "Retail Electric Competition Rules" below), APS is the "provider of last resort" for standard offer customers under rates that have been approved by the ACC. Energy prices in the western wholesale market vary and, during the course of the last year, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in APS' current retail rates. APS expects these market conditions to continue in 2001. We believe we have adequately supplemented our current generation portfolio with power purchased through contracts and hedging techniques that limit exposure to the volatile spot wholesale power market. However, in the event of shortfalls due to unforeseen increases in load demand or generation outages, APS may need to purchase additional supplemental power in the wholesale spot market. Unless APS is able to obtain an adjustment of its rates under the 1999 Settlement Agreement, there can be no assurance that APS would be able to fully recover the costs of this power. RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to approve rules that provide a framework for the introduction of retail electric competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, APS must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement. On December 8, 1999, APS filed a lawsuit to protect its legal rights regarding the Rules. This lawsuit is pending, along with several other lawsuits on ACC orders relating to stranded cost recovery (including those described above involving APS),
-11- the adoption or amendment of the Rules, and the certification of competitive electric service providers. On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of APS' property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have appealed the ruling to the Arizona Court of Appeals, as a result of which the Superior Court's ruling is automatically stayed pending further judicial review. In a similar appeal concerning the issuance of telecommunications CC&N's, the Arizona Court of Appeals invalidated rates for competitive carriers due to failure to establish a fair value rate base. The Rules approved by the ACC include the following major provisions: * They apply to virtually all Arizona electric utilities regulated by the ACC, including APS. * Effective January 1, 2001, retail access became available to all APS retail electricity customers. * Electric service providers that get 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 1999 Settlement Agreement, APS received a waiver to allow transfer of its generation and other competitive assets and services to affiliates no later than December 31, 2002. See "1999 Settlement Agreement" above for a discussion of the planned timing of the transfer. 1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory agreement between the ACC Staff and APS. Based on the price reduction formula authorized in the agreement, the ACC approved retail price decreases (approximate) as follows (dollars in millions):
-12- 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 1999 Settlement Agreement (see above). The regulatory agreement also required that we infuse $200 million of common equity into APS 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, results of operations, or liquidity. 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 1992 Energy Act and recent rulemakings by FERC have promoted increased competition in the wholesale energy markets. We do not expect these rules to have a material impact on our financial statements.
-13- Several electric utility industry restructuring bills will undoubtedly be introduced during the current congressional session. Several bills have been written to allow consumers to choose their electricity suppliers beginning in 2001 and beyond. These bills and other bills 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, APS 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 APS' 29.1% interest in the three Palo Verde units, APS' 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 damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. APS has also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen 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 activities (delivery business segment) and the generation of electricity and wholesale activities (generation business segment). These reportable segments reflect a change in the reporting of our functional activities. Previously reported segment information combined transmission and distribution of electricity activities with wholesale activities. Our current operational activities are more closely based on the strong integration of our wholesale activities and our generation of electricity activities, and have been combined for segment reporting purposes. The corresponding information for earlier periods has been restated.
-14- The other amounts include activity relating to the parent company and other subsidiaries, including APS Energy Services, SunCor and El Dorado. Eliminations primarily relate to intersegment sales of electricity. Segment information for the three and twelve months ended March 31, 2001 and 2000 is as follows (dollars in millions): 3 Months Ended 12 Months Ended March 31, March 31, ------------------- ------------------- 2001 2000 2001 2000 ------- ------- ------- ------- Operating Revenues: Delivery $ 408 $ 372 $ 2,006 $ 1,817 Generation 694 246 2,910 1,337 Other 38 42 178 148 Eliminations (201) (172) (953) (829) ------- ------- ------- ------- Total $ 939 $ 488 $ 4,141 $ 2,473 ======= ======= ======= ======= Income from Continuing Operations: Delivery $ 24 $ 24 $ 105 $ 146 Generation 42 9 232 121 Other (4) 21 (27) 26 ------- ------- ------- ------- Total $ 62 $ 54 $ 310 $ 293 ======= ======= ======= ======= As of March 31, As of December 31, 2001 2000 ------- ------- Assets: Delivery $ 3,949 $ 3,987 Generation 3,081 2,687 Other 566 475 ------- ------- Total $ 7,596 $ 7,149 ======= ======= 9. Accounting Matters 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 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 derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances/credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. In addition, subject to specified risk parameters established by the Board of Directors and monitored by the ERMC, we engage in trading activities intended to profit from market price movements. Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are
-15- either recognized periodically in income or shareholder's equity (as a component of other comprehensive income), depending on whether or not the derivative meets specific hedge accounting criteria. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness is recognized immediately in net income. This new standard may result in additional volatility in our net income and comprehensive income. As a result of adopting SFAS No. 133, we recognized $118 million of derivative assets and $16 million of derivative liabilities in our balance sheet as of January 1, 2001. Also as of January 1, 2001, we recorded a $3 million after-tax loss in net income as a cumulative effect of a change in accounting principles and a $65 million after-tax gain in equity (as a component of other comprehensive income). The gain resulted from unrealized gains on cash flow hedges. For the three and twelve months ended March 31, 2001, a net gain of approximately $2 million pretax was recognized in earnings (recorded in fuel and purchased power) representing the amount of hedge ineffectiveness. We excluded the time value component of options from the assessment of hedge effectiveness and there were no reclassifications into earnings as a result of the discontinuance of hedges. As of March 31, 2001, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is forty-five months. During the twelve months ending March 31, 2002, we estimate that a net gain of $43 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect on earnings of market price changes for the related hedged transaction. In December 2000, the FASB's DIG discussed whether contracts in the electric industry that have some of the characteristics of purchased and written options should qualify for the "normal purchases and sales" scope exception. The DIG did not reach a conclusion on this issue. We account for electricity contracts with characteristics of options as normal purchases and sales if it is probable that the contract, if exercised, will not be settled in cash and will result in the physical delivery of electricity. As a result, we do not mark these contracts to their fair market values each reporting period. The DIG also discussed but did not determine whether electricity contracts subject to "bookout" should qualify for the normal scope exception. A bookout occurs when one party appears more than once in a contract path for the sale and purchase of energy. In that instance, the counterparties may agree that they will not schedule or deliver physical energy that originates and ends with the same counterparty, but rather will settle in cash the amounts due to or from each counterparty. We account for our non-trading electricity transactions that bookout as gross settlement with physical delivery (and eligible for the normal scope exception) if title transfers, gross cash payment is made, and the transaction retains both performance and credit risk. Trading contracts are marked to their fair market values each reporting period. In March 2001, the FASB discussed contracts in the electric industry that have some of the characteristics of purchased and written options. There was not sufficient FASB support for providing an exception that would enable electricity option contracts to be eligible to qualify for the normal purchases and sales exception. The DIG also concluded that contracts that are subject to being booked out are prohibited from qualifying for the normal purchase and sale scope exception. Both decisions are subject to a comment
-16- period, which ends on June 1, 2001. Final guidance is expected in the second quarter. Until final guidance is issued, we will continue to account for these transactions as normal purchases and sales. We are currently evaluating the impact the proposed guidance would have on our financial statements. Our accounting approach for non-trading electricity contracts, as described above, reflects the non-storability of electricity and the unpredictability of electricity demand at any point in time. If the FASB or DIG ultimately provides us with contrary guidance, we will be required to mark certain of our non-trading electricity contracts to their fair market values each reporting period. This could have a material impact on our financial statements and add significant volatility in both net income and comprehensive income that would not be reflective of our underlying financial performance or condition. If we are required in the future to treat these contracts as derivative instruments, we will apply a cumulative effect of a change in accounting principles in the quarter following final resolution of the issues. In February 1996, the FASB issued an exposure draft, "Accounting for Certain Liabilities Related to Closure or Removal of Long-Lived Assets." This proposed standard would require the estimated present value of the cost of decommissioning and certain other removal costs to be recorded as a liability, along with an offsetting plant asset when a decommissioning or other removal obligation is incurred. The FASB issued a revised exposure draft in February 2000 and we are evaluating the impacts. 10. Comprehensive Income Components of comprehensive income for the three-month and twelve-month periods ended March 31, 2001 and 2000, are as follows (dollars in thousands): <TABLE> <CAPTION> 3 Months Ended 12 Months Ended March 31, March 31, ----------------------- ----------------------- 2001 2000 2001 2000 --------- --------- --------- --------- <S> <C> <C> <C> <C> Net income $ 59,450 $ 54,070 $ 307,712 $ 191,267 --------- --------- --------- --------- Other comprehensive income: Cumulative effect of change in accounting for derivatives, net of tax of $42,101 64,700 -- 64,700 -- Unrealized holding losses arising during period, net of tax of $3,681 (5,657) -- (5,657) -- Reclassification adjustment for realized gains on derivatives, net of tax of $14,067 (21,618) -- (21,618) -- --------- --------- --------- --------- Total other comprehensive income 37,425 -- 37,425 -- --------- --------- --------- --------- Comprehensive income $ 96,875 $ 54,070 $ 345,137 $ 191,267 ========= ========= ========= ========= </TABLE>
-17- 11. Generation Expansion Pinnacle West Energy has announced plans to build up to 2,800 MW of generating capacity from 2001-2006 at an estimated cost of about $1.3 billion. Pinnacle West Energy is also considering additional expansion over the next several years, which may result in additional expenditures. Pinnacle West Energy expects to fund its capital expenditures through internally generated cash, debt issued directly by Pinnacle West Energy, and capital infusions from the parent company's internally generated cash and external financing. Pinnacle West Energy is currently planning a 650-megawatt expansion of the West Phoenix Power Plant and the construction of a natural gas-fired electric generating station of up to four, 530 MW units, near Palo Verde, called Redhawk. Construction on the 120 MW West Phoenix Unit 4 began in June 2000, with commercial operation of the unit expected in the summer of 2001. Pinnacle West Energy expects construction to begin on the 530 MW West Phoenix Unit 5 in the fall of 2001, with commercial operation expected to begin in mid-2003. Construction began on the first two units of Redhawk in December 2000, and commercial operation is currently scheduled for the summer of 2002. Pinnacle West Energy has entered into an agreement with NPC to purchase NPC's 72 MW gas-fired Harry Allen Power Station about 30 miles northeast of Las Vegas, Nevada, for a net purchase price, after adjustments for purchased power commitments, of approximately $65.2 million. The purchase is subject to filing with and/or approval of various regulatory agencies, including FERC and the NPUC. The filing with the NPUC was made in February 2001. NPC will have the right, but not the obligation, to purchase the output from the Harry Allen plant at market rates, subject to a floor and a cap. As demand grows in the region during the next five years, Pinnacle West Energy would expect to add a 480 MW gas-fired, combined cycle unit to the site. However, recently-enacted Nevada legislation provides that "[b]efore July 1, 2003, an electric utility shall not dispose of a generation asset." Although the NPC purchase agreement remains in effect, unless this Nevada law is amended, Pinnacle West Energy would not be able to acquire the Harry Allen Power Station under the NPC purchase agreement. On April 27, 2000, Pinnacle West Energy entered into two separate agreements with SCE to purchase SCE's 15.8% ownership interest in Palo Verde and its 48% ownership interest in the Four Corners Power Plant. By letter dated April 23, 2001, Pinnacle West Energy informed SCE that it was terminating each of the agreements in accordance with its terms, effective April 24, 2001. 12. Income Tax Benefit In September 1999, we recorded a tax benefit of $38 million, or $0.45 per basic or diluted share, which stemmed from the resolution of income tax matters related to a former subsidiary, MeraBank, A Federal Savings Bank. This amount is reflected as a tax benefit from discontinued operations in the income statement.
-18- 13. El Dorado Partnership Investment Income Net other income consists primarily of El Dorado's share in the earnings of a venture capital partnership. Prior to 2001, we recorded our share of the earnings from the partnership, as the partnership adjusted the value of its investment. In 2001, El Dorado received a distribution of securities representing substantially all of El Dorado's investment in the partnership. The securities were sold in the first quarter of 2001 and a gain was recognized in other income. 14. California Energy Market Issues We are closely monitoring developments in the California energy market and the potential impact of these developments on us and our subsidiaries. We have evaluated, among other things, SCE's role as a Palo Verde and Four Corners participant; APS' transactions with the PX and the ISO; contractual relationships with SCE and PG&E; APS Energy Services' retail transactions involving SCE and PG&E; and power marketing exposures. Based on our current evaluations, we have reserved $10 million before income taxes for our credit exposure related to the California energy situation. We cannot predict with certainty, however, the impact that any future resolution, or attempted resolution, of the California energy market situation may have on us or our subsidiaries or the regional energy market in general. 15. Legal Proceedings SunCor is a party to a lawsuit pending in Maricopa County Superior Court entitled SUNCOR DEVELOPMENT COMPANY V. BERGSTROM CORPORATION, CV 98-11472. On March 15, 2001, a jury returned a verdict against SunCor in the amount of $28.6 million, $25.7 million of which represents a punitive damage award. The verdict was based on the Bergstrom Corporation's claims that it was defrauded in connection with the acquisition of approximately ten acres of land in a SunCor commercial development and a subsequent settlement agreement relating to those claims. SunCor believes that the verdict is neither supported by the evidence or the law and intends to vigorously pursue post-trial motions and, if necessary, an appeal. We do not expect this litigation to have a material adverse impact on our financial position, results of operation or liquidity. 16. Power Service Agreement APS is a party to a power service agreement with Citizens under which APS supplies Citizens with power. By letter dated March 7, 2001, Citizens advised APS that it believes APS has overcharged Citizens by over $50 million under the agreement since the summer of 2000. APS believes that its charges to Citizens under the agreement are fully in accordance with the terms of the agreement and APS will vigorously defend any claims raised by Citizens.
-19- PINNACLE WEST CAPITAL CORPORATION ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. INTRODUCTION In this section, we explain the results of operations, general financial condition, and outlook for Pinnacle West and our subsidiaries: APS, Pinnacle West Energy, APS Energy Services, SunCor, and El Dorado, including: * the changes in our earnings for the three-month and twelve-month periods ended March 31, 2001 and 2000; * the effects of regulatory agreements on our results and outlook; * our capital needs and resources; * major factors that affect our financial outlook; and * our management of market risks. We suggest this section be read along with the 2000 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 Consolidated Financial Statements in this report. These Notes add further details to the discussion. OVERVIEW OF OUR BUSINESS Pinnacle West owns all of the outstanding common stock of APS. APS is Arizona's largest electric utility and provides retail and wholesale electric service to the entire state with the exception of Tucson and about one-half of the Phoenix area. APS also generates and, directly or through our power marketing division, sells and delivers electricity to wholesale customers in the western United States. Our other major subsidiaries are wholly-owned and are: * Pinnacle West Energy, through which we intend to conduct our unregulated generation operations; * APS Energy Services, which sells energy and energy-related products and services in competitive retail markets in the western United States; * SunCor, which is a developer of residential, commercial, and industrial real estate projects in Arizona, New Mexico, and Utah; and * El Dorado, which is an investment firm.
-20- We have two principal business segments, determined by products, services, and regulatory environment: * The electricity delivery business segment, which consists of the transmission and distribution of electricity activities; and * The generation business segment, which consists of our generation and wholesale activities. See "Business Segments" in Note 8 for more information about our business segments. In general, we have structured our discussion below based on existing legal entities. The "Operating Results," for example, primarily reflect the results of APS' operations because APS currently owns the substantial portion of our assets and produces substantially all of our profits. OPERATING RESULTS The following table summarizes net income for the three-month and twelve-month periods ended March 31, 2001 and the comparable prior year periods for Pinnacle West and each of its subsidiaries (dollars in millions): 3 Months Ended 12 Months Ended March 31, March 31, ---------------- ---------------- 2001 2000 2001 2000 ----- ----- ----- ----- APS $ 65 $ 33 $ 338 $ 267 Pinnacle West Energy -- -- (2) -- APS Energy Services (8) (2) (20) (9) SunCor -- 5 7 10 El Dorado -- 19 (17) 31 Parent company 5 (1) 5 (6) ----- ----- ----- ----- Income from continuing operations 62 54 311 293 Income tax benefit from discontinued operations -- -- -- 38 Extraordinary charge - net of income taxes of $94 -- -- -- (140) Cumulative effect of a change in accounting - net of income taxes of $2 (3) -- (3) -- ----- ----- ----- ----- Net Income $ 59 $ 54 $ 308 $ 191 ===== ===== ===== =====
-21- OPERATING RESULTS - THREE-MONTH PERIOD ENDED MARCH 31, 2001 COMPARED WITH THREE-MONTH PERIOD ENDED MARCH 31, 2000 Our consolidated net income for the three months ended March 31, 2001 was $59 million compared with $54 million for the same period in the prior year. In January 2001, we recognized a $3 million after-tax loss in net income as a cumulative effect of a change in accounting for derivatives. See Note 9 for further discussion. Income before accounting change for the three-month period increased $8 million, or 15%, over the comparable period in 2000 primarily because of increases in wholesale and retail electricity sales. These positive factors more than offset decreases resulting from lower earnings from El Dorado, higher operations and maintenance expenses, reductions in retail electricity prices, and miscellaneous factors. See Note 6 for information on the price reductions. Electric operating revenues increased approximately $460 million primarily because of: * increased wholesale revenues ($439 million); * weather impacts on retail revenues ($17 million); and * increased retail revenues related to the number of electricity customers and the average amount of electricity used by customers ($14 million). As mentioned above, these positive factors were partially offset by reductions in retail electricity prices ($6 million) and other miscellaneous factors ($4 million). The increase in wholesale revenues resulted primarily from higher prices and increased activity in western U.S. wholesale power markets. These revenues were accompanied by increases in purchased power and fuel expense of approximately $329 million. Fuel and purchased power expenses were also higher because of increased prices and higher retail electricity sales volumes. The increase in operations and maintenance expenses primarily related to power plant maintenance and a provision for credit exposure related to the California energy situation. See "Business Outlook - California Energy Market Issues" below. Net other income decreased $36 million primarily because of an increase in the market value of El Dorado's investment in a technology-related venture capital partnership recognized in the first quarter of 2000. See Note 13 for additional information. OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED MARCH 31, 2001 COMPARED WITH TWELVE-MONTH PERIOD ENDED MARCH 31, 2000 Consolidated net income for the twelve months ended March 31, 2001 was $308 million compared with $191 million for the same period in the prior year. The increase primarily relates to a $140 million after-tax extraordinary charge recorded in the third quarter
-22- of 1999 and higher income from continuing operations in the twelve-month period ended March 31, 2001, partially offset by a $38 million income tax benefit from discontinued operations (also recorded in the third quarter of 1999) and a $3 million after-tax loss for a cumulative effect of a change in accounting for derivatives recorded in 2001. The extraordinary charge related to a regulatory disallowance that resulted from APS' 1999 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 1999 Settlement Agreement. The income tax benefit from discontinued operations resulted from the resolution of income tax matters related to a former subsidiary, MeraBank. See Note 12. The cumulative effect of a change in accounting for derivatives resulted from the implementation of SFAS No. 133. See Note 9. Income from continuing operations for the twelve-months ended March 31, 2001 increased $17 million over the comparable prior-year period primarily because of an increase in the contribution of wholesale power marketing activities and an increase in the number of retail electricity customers and in the average amount of electricity used by customers. These positive factors more than offset decreases due to decreased earnings from El Dorado, the completion of the amortization of ITCs in 1999, reductions in retail electricity prices, higher depreciation expense, higher operations and maintenance expenses 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 approximately $1.7 billion because of: * increased wholesale revenues ($1.5 billion); * increases in the number of customers and the average amount of electricity used by customers ($93 million); * weather impacts on retail revenues ($49 million); and * miscellaneous factors ($8 million). These positive factors were partially offset by reductions in retail electricity prices ($28 million). The increase in 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 approximately $1.3 billion. Fuel and purchased power expenses were also higher because of increased prices and higher retail electricity sales volumes. The increase in operations and maintenance expenses primarily related to provisions for credit exposure related to the California energy situation, increases in customer growth, offset by approximately $20 million of non-recurring items recorded in 1999. See "Business Outlook - California Energy Market Issues" below.
-23- Depreciation and amortization expense increased primarily because of higher plant balances. Net other income decreased $85 million primarily because of a change in the market value of El Dorado's investment in a technology-related venture capital partnership. See Note 13 for additional information. INCOME TAXES As part of a 1994 rate settlement, APS accelerated amortization of substantially all of its ITCs over a five-year period that ended on December 31, 1999. The amortization of ITCs decreased annual consolidated income tax expense by approximately $24 million. Beginning in 2000, no further benefits were being reflected in income tax expense related to the acceleration of the ITCs. LIQUIDITY AND CAPITAL RESOURCES CAPITAL EXPENDITURE REQUIREMENTS The following table summarizes the actual capital expenditures for the period ended March 31, 2001 and estimated capital expenditures for the next three years: CAPITAL EXPENDITURES (dollars in millions) (actual) (estimated) ------------------ ------------------------------ Three-months ended Years ending December 31, March 31, 2001 2001 2002 2003 -------------- ------ ------ ------ APS Delivery $ 78 $ 337 $ 293 $ 294 Existing generation (a) 24 118 108 -- ------ ------ ------ ------ 102 455 401 294 ------ ------ ------ ------ Pinnacle West Energy (b) Generation expansion 90 659 129 132 Existing generation (a) -- -- -- 122 ------ ------ ------ ------ 90 659 129 254 ------ ------ ------ ------ SunCor (c) 31 75 23 14 ------ ------ ------ ------ Other (d) -- 21 9 9 ------ ------ ------ ------ Total $ 223 $1,210 $ 562 $ 571 ====== ====== ====== ====== (a) Pursuant to the 1999 Settlement Agreement, APS is required to move its generating assets and competitive services no later than December 31, 2002.
-24- (b) See Note 11 and "Capital Resources and Cash Requirements - Pinnacle West Energy" below. (c) Consists primarily of capital expenditures for land development and retail and office building construction. (d) Primarily APS Energy Services. CAPITAL RESOURCES AND DEBT FINANCING PINNACLE WEST The parent company's cash requirements and its ability to fund those requirements are discussed under "Capital Needs and Resources" in Management's Discussion and Analysis of Financial Condition and Results of Operation in Part II, Item 7 of the 2000 10-K. During the three-months ended March 31, 2001, the parent company increased its outstanding indebtedness by about $255 million. During the three-month period ended March 31, 2001, the parent company issued $300 million in long-term debt and $97 million in short-term borrowings and repaid $142 million of long- and short-term debt. The majority of these borrowings were used to fund Pinnacle West Energy capital expenditures. On May 1, 2001, we initiated a $250 million commercial paper program. We also held temporary investments of approximately $113 million at March 31, 2001. APS APS' long-term debt redemption requirements, including optional repayments on long-term debt are: $380 million in 2001; $125 million in 2002; and zero in 2003. During the three months ended March 31, 2001, APS satisfied its long-term debt redemption requirements for the first quarter of 2001 with cash from operations and short-term borrowings. On April 15, 2001, APS redeemed $45 million (plus interest) of its First Mortgage Bonds, 9 1/2% Series due 2021. APS has also deposited $72 million, plus interest, with the trustee for the redemption in December 2001 of its First Mortgage Bonds, 9% Series due 2021. Based on market conditions and optional call provisions, APS may make optional redemptions of long-term debt from time to time. Although provisions in APS' first mortgage bond indenture, articles of incorporation, and ACC financing orders establish maximum amounts of additional first mortgage bonds and preferred stock that APS may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements.
-25- PINNACLE WEST ENERGY Pinnacle West Energy has announced plans to build up to 2,800 MW of generating capacity from 2001-2006 at an estimated cost of about $1.3 billion. Site MW ---- ---- West Phoenix 4 120 West Phoenix 5 530 Redhawk 1 530 Redhawk 2 530 Redhawk 3 530 Redhawk 4 530 ----- TOTAL 2,770 ===== Pinnacle West Energy is also considering additional expansion, which may result in additional expenditures. Pinnacle West Energy expects to fund its capital requirements through internally generated cash, debt issued directly by Pinnacle West Energy, and capital infusions from the parent company's internally generated cash and external financing. Pinnacle West Energy is currently planning a 650 MW expansion of the West Phoenix Power Plant and the construction of a natural gas-fired electric generating station of up to four, 530 MW units, near Palo Verde, called Redhawk. Construction on the 120 MW West Phoenix Unit 4 began in June 2000, with commercial operation of the unit expected in the summer of 2001. Pinnacle West Energy expects construction to begin on the 530 MW West Phoenix Unit 5 in the fall of 2001, with commercial operation expected to begin in mid-2003. Construction began on the first two units of Redhawk in December 2000, and commercial operation is currently scheduled for the summer of 2002. Pinnacle West Energy has entered into an agreement with NPC to purchase NPC's 72 MW gas-fired Harry Allen Power Station about 30 miles northeast of Las Vegas, Nevada, for a net purchase price, after adjustments for purchased power commitments, of approximately $65.2 million. The purchase is subject to filing with and/or approval of various regulatory agencies, including the FERC and the NPUC. The filing with the NPUC was made in February 2001. NPC will have the right, but not the obligation, to purchase the output from the Harry Allen plant at market rates, subject to a floor and a cap. As demand grows in the region during the next five years, Pinnacle West Energy expects to add a 480 MW gas-fired, combined cycle unit to the site. However, recently-enacted Nevada legislation provides that "[b]efore July 1, 2003, an electric utility shall not dispose of a generation asset." Although the NPC purchase agreement remains in effect, unless this Nevada law is amended, Pinnacle West Energy would not be able to acquire the Harry Allen Power Station under the NPC purchase agreement. On April 27, 2000, Pinnacle West Energy entered into two separate agreements with SCE to purchase SCE's 15.8% ownership interest in Palo Verde and its 48% ownership
-26- interest in the Four Corners Power Plant. By letter dated April 23, 2001, Pinnacle West Energy informed SCE that it was terminating each of the agreements in accordance with its terms, effective April 24, 2001. OTHER SUBSIDIARIES SunCor and El Dorado each fund all of their cash requirements with cash from operations and, in the case of SunCor, its own external financings. APS Energy Services funds its cash requirements with cash infusions from the parent company. SunCor's capital needs consist primarily of capital expenditures for land development and retail and office building construction. See the Capital Expenditures table above for actual capital expenditures for the three-months ended March 31, 2001 and projected capital expenditures through 2003. SunCor expects to fund its capital requirements from internally generated cash and its own external financings. El Dorado intends to focus on the realization of the value of its existing investments and does not have any capital requirements over the next three years. El Dorado's future investments are expected to be limited to opportunities related to the energy sector. BUSINESS OUTLOOK This section describes several major factors affecting our financial outlook. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See "Business Outlook - Competition and Industry Restructuring" in Item 7 of the 2000 10-K and Note 6 above for a discussion of developments affecting retail and wholesale electric competition. See Note 5 for a discussion of regulatory accounting. GENERATION EXPANSION See "Liquidity and Capital Resources -- Capital Resources and Debt Financing - Pinnacle West Energy" and Note 11 for information regarding our generation expansion plans. The planned additional generation is expected to increase revenues, fuel expenses, operating expenses, and financing costs. CALIFORNIA ENERGY MARKET ISSUES SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and ISO. In April 2001, PG&E filed for bankruptcy protection. We are closely monitoring developments in the California energy market and the potential impact of these developments on us and our subsidiaries. We have evaluated, among other things, SCE's role as a Palo Verde and Four Corners participant; APS' transactions with the PX and the ISO; contractual relationships with SCE and PG&E; APS Energy Services' retail transactions involving SCE and PG&E; and power marketing
-27- exposures. Based on our current evaluations, we have reserved $10 million before income taxes for our credit exposure related to the California energy situation. We cannot predict with certainty, however, the impact that any future resolution, or attempted resolution, of the California energy market situation may have on us or our subsidiaries or the regional energy market in general. FACTORS AFFECTING OPERATING REVENUES Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona, and in competitive retail and wholesale bulk power markets in the western United States. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer, as well as electricity prices and variations in weather from period to period. In APS' regulated retail market area, APS 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 APS' service territory averaged 3.8% a year for the three years 1998 through 2000; we currently expect customer growth to average 3.5% to 4% a year for 2001 through 2003. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 4.5% a year in 2001 through 2003, before the retail effects of weather variations. The customer growth and sales growth referred to in this paragraph apply to energy delivery customers. As industry restructuring evolves in the regulated market area, we cannot predict the number of APS' standard offer customers that will switch to unbundled service. Wholesale activities will be affected by electricity prices and costs of available fuel and purchased power 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 power activities and their resultant earnings contributions over the last several years. We cannot predict future contributions from wholesale activities. Competitive sales of energy and energy-related products and services are made by APS Energy Services in western states that have opened to competitive supply. Such activities are currently not material to our consolidated financial results. OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS 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. Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant operations, inflation, and other factors. Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property, changes in regulatory asset amortization, and our
-28- generation expansion program. See Note 5 for the regulatory asset amortization that is being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement. 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 increase primarily due to our generation expansion program and our additions to existing facilities. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our generation expansion program and our internally generated cash flow. The annual earnings contribution from our real estate subsidiary, SunCor, is expected to remain modest over the next several years. El Dorado's historical results are not necessarily indicative of future performance for El Dorado. See Note 13 for additional information regarding El Dorado. El Dorado's strategies focus on realization of the value of its existing investments. Any future investments are expected to be related to the energy business. We cannot accurately predict the impact of full retail competition on our financial position, cash flows, results of operations, or liquidity. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete effectively in a restructured industry. Our financial results may be affected by the application of SFAS No. 133. See Note 9 for further information. Our financial results may be affected by a number of broad factors. See "Forward-Looking Statements" below for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate. RATE MATTERS See Note 6 for a discussion of a price reduction effective as of July 1, 2000, and for a discussion of the 1999 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 This document contains forward-looking statements based on current expectations and we assume no obligation to update these statements. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include the ongoing restructuring of the electric industry; the outcome of regulatory and legislative proceedings relating to the restructuring; regional economic and market conditions, including the California energy situation, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital; weather variations affecting
-29- local and regional customer energy usage; conservation programs; power plant performance; the successful completion of our generation expansion program; regulatory issues associated with generation expansion, such as permitting and licensing; our ability to compete successfully outside traditional regulated markets (including the wholesale market); technological developments in the electric industry; and the real estate market in SunCor's market areas, which include Arizona, New Mexico and Utah. 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 our 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 ensure that we have enough energy for our customers and limit our exposure to volatile wholesale prices for power and fuel. In addition, we engage in trading activities intended to profit from favorable movements of market prices. As of March 31, 2001, 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 $66 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 complete the move of our wholesale power marketing and trading activities from APS to the parent company by the end of 2002. 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 consolidated earnings for a given period. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our 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.
-30- 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 and its subsidiaries. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See Note 6 of Notes to Condensed Consolidated 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. WATER SUPPLY A summons served on APS in early 1986 required all water claimants in the Lower Gila River Watershed in Arizona to assert any claims to water on or before January 20, 1987. See "Water Supply" in Part I, Item 1 of the 2000 10-K. APS and other parties have petitioned the U.S. Supreme Court for review of the Arizona Supreme Court's decision affirming the lower court's criteria for resolving groundwater claims.
-31- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below: <TABLE> <CAPTION> Exhibit No. Description Originally Filed as Exhibit: File No(a) Date Effective - ----------- ----------- ---------------------------- ---------- -------------- <S> <C> <C> <C> <C> 10.1 Articles of Incorporation 19.1 to the Company's 1-8962 11-14-88 restated as of July 29, 1988 September 30, 1988 Form 10-Q Report 10.2 Bylaws, amended as of 4.1 to the Company's 1-8962 1-20-00 December 15, 1999 Registration Statement on Form S-8 No. 333-95035 </TABLE> (b) Reports on Form 8-K During the quarter ended March 31, 2001, and the period from April 1 through May 15, 2001, we filed the following reports on Form 8-K: Report dated November 27, 2000, regarding (i) the Court of Appeals affirming the ACC approval of the 1999 Settlement Agreement, (ii) a final judgment relating to the Rules and (iii) the timing of the Company's restructuring, and (iv) generation expansion. Report dated March 15, 2001 regarding a jury verdict against SunCor. Report dated March 21, 2001 comprised of Exhibits to the Company's Registration Statement No. 333-52476 relating to the Company's offering of $300 million of Senior Notes. Report dated April 5, 2001 regarding (i) the Arizona Court of Appeals affirming the ACC's approval of the 1999 Settlement Agreement and (ii) the written materials to be presented at analyst conferences on April 10 and April 11, 2001. - ---------- (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.
-32- 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. PINNACLE WEST CAPITAL CORPORATION (Registrant) Dated: May 15, 2001 By: Chris N. Froggatt ------------------------------------ Chris N. Froggatt Vice President and Controller (Principal Accounting Officer and Officer Duly Authorized to sign this Report)