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, 1999 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 E. Van Buren St., P.O. Box 52132, Phoenix, Arizona 85072-2132 - ------------------------------------------------------ ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (602) 379-2500 ---------------------------------------------------- (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 August 12, 1999: 84,764,309
Glossary ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission APS - Arizona Public Service Company APS Energy Services - APS Energy Services Company, Inc., a direct access electricity provider Company - Pinnacle West Capital Corporation DOE - United States Department of Energy EITF - Emerging Issues Task Force EITF 97-4 - Emerging Issues Task Force Issue No. 97-4, "Deregulation of the Pricing of Electricity -- Issues Related to the Applications 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" El Dorado - El Dorado Investment Company EPA - Environmental Protection Agency FASB - Financial Accounting Standards Board FERC - Federal Energy Regulatory Commission ITC - Investment tax credit March 10-Q - Pinnacle West Capital Corporation Quarterly Report on Form 10-Q for the fiscal quarter ended March 31, 1999 1998 10-K - Pinnacle West Capital Corporation Annual Report on Form 10-K for the fiscal year ended December 31, 1998 MW - Megawatt, one million watts Palo Verde - Palo Verde Nuclear Generating Station Pinnacle West - Pinnacle West Capital Corporation Power Coordination Agreement - 1955 agreement between the Company and Salt River Project that provides for certain electric system and power sales SFAS No. 71 - Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation"
-2- 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 SunCor - SunCor Development Company Territorial Agreement - 1955 agreement between the Company and Salt River Project that has provided exclusive retail service territories in Arizona for each party
-3- 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) Three Months Ended June 30, ---------------------------- 1999 1998 ------------ ------------ Operating Revenues Electric $ 511,434 $ 441,715 Real estate 32,697 28,916 ------------ ------------ Total 544,131 470,631 ------------ ------------ Operating Expenses Fuel and purchased power 132,543 95,585 Utility operations and maintenance 106,234 102,713 Real estate operations 29,401 26,213 Depreciation and amortization 97,383 93,585 Taxes other than income taxes 29,602 29,930 ------------ ------------ Total 395,163 348,026 ------------ ------------ Operating Income 148,968 122,605 ------------ ------------ Other Income (Expense) Preferred stock dividend requirements of APS -- (2,435) Net other income and expense 399 192 ------------ ------------ Total 399 (2,243) ------------ ------------ Income Before Interest and Income Taxes 149,367 120,362 ------------ ------------ Interest Expense Interest charges 41,105 42,441 Capitalized interest (4,189) (4,874) ------------ ------------ Total 36,916 37,567 ------------ ------------ Income Before Income Taxes 112,451 82,795 Income Taxes 43,749 33,798 ------------ ------------ Net Income $ 68,702 $ 48,997 ============ ============ Average Common Shares Outstanding - Basic 84,716,175 84,810,790 Average Common Shares Outstanding - Diluted 85,093,421 85,416,069 Earnings Per Average Common Share Outstanding Net income - basic $ 0.81 $ 0.58 Net income - diluted $ 0.81 $ 0.57 Dividends Declared Per Share $ 0.65 $ 0.60 ============ ============ See Notes to Condensed Consolidated Financial Statements.
-4- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (Dollars in thousands, except per share amounts) Six Months Ended June 30, ---------------------------- 1999 1998 ------------ ------------ Operating Revenues Electric $ 925,417 $ 822,138 Real estate 57,230 63,077 ------------ ------------ Total 982,647 885,215 ------------ ------------ Operating Expenses Fuel and purchased power 231,784 169,502 Utility operations and maintenance 205,318 199,129 Real estate operations 51,636 56,449 Depreciation and amortization 194,293 186,415 Taxes other than income taxes 59,049 60,278 ------------ ------------ Total 742,080 671,773 ------------ ------------ Operating Income 240,567 213,442 ------------ ------------ Other Income (Expense) Preferred stock dividend requirements of APS (1,016) (5,313) Net other income and expense (1,938) 4,551 ------------ ------------ Total (2,954) (762) ------------ ------------ Income Before Interest and Income Taxes 237,613 212,680 ------------ ------------ Interest Expense Interest charges 81,874 85,363 Capitalized interest (8,263) (9,530) ------------ ------------ Total 73,611 75,833 ------------ ------------ Income Before Income Taxes 164,002 136,847 Income Taxes 64,610 56,764 ------------ ------------ Net Income $ 99,392 $ 80,083 ============ ============ Average Common Shares Outstanding - Basic 84,693,115 84,798,120 Average Common Shares Outstanding - Diluted 85,135,423 85,375,609 Earnings Per Average Common Share Outstanding Net income - basic $ 1.17 $ 0.94 Net income - diluted $ 1.17 $ 0.94 Dividends Declared Per Share $ 0.975 $ 0.90 ============ ============ See Notes to Condensed Consolidated Financial Statements.
-5- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) (Dollars in thousands, except per share amounts) Twelve Months Ended June 30, ---------------------------- 1999 1998 ------------ ------------ Operating Revenues Electric $ 2,109,677 $ 1,862,919 Real estate 118,341 129,841 ------------ ------------ Total 2,228,018 1,992,760 ------------ ------------ Operating Expenses Fuel and purchased power 599,783 421,350 Utility operations and maintenance 420,230 421,385 Real estate operations 110,518 120,014 Depreciation and amortization 387,557 370,289 Taxes other than income taxes 115,677 121,269 ------------ ------------ Total 1,633,765 1,454,307 ------------ ------------ Operating Income 594,253 538,453 ------------ ------------ Other Income (Expense) Preferred stock dividend requirements of APS (5,406) (11,295) Net other income and expense (5,880) 74 ------------ ------------ Total (11,286) (11,221) ------------ ------------ Income Before Interest and Income Taxes 582,967 527,232 ------------ ------------ Interest Expense Interest charges 165,656 176,207 Capitalized interest (17,329) (19,223) ------------ ------------ Total 148,327 156,984 ------------ ------------ Income Before Income Taxes 434,640 370,248 Income Taxes 172,439 146,873 ------------ ------------ Net Income $ 262,201 $ 223,375 ============ ============ Average Common Shares Outstanding - Basic 84,722,147 84,767,601 Average Common Shares Outstanding - Diluted 85,232,428 85,298,571 Earnings Per Average Common Share Outstanding Net income - basic $ 3.09 $ 2.64 Net income - diluted $ 3.08 $ 2.62 Dividends Declared Per Share $ 1.30 $ 1.20 ============ ============ See Notes to Condensed Consolidated Financial Statements.
-6- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS ASSETS (Thousands of Dollars) June 30, December 31, 1999 1998 (Unaudited) ---------- ---------- Current Assets Cash and cash equivalents $ 32,511 $ 20,538 Customer and other receivables--net 185,701 233,876 Accrued utility revenues 98,046 67,740 Materials and supplies 70,919 69,074 Fossil fuel 17,786 13,978 Deferred income taxes 4,058 3,999 Other current assets 55,923 47,594 ---------- ---------- Total current assets 464,944 456,799 ---------- ---------- Investments and Other Assets Real estate investments--net 335,977 331,021 Other assets 262,586 236,562 ---------- ---------- Total investments and other assets 598,563 567,583 ---------- ---------- Utility Plant Electric plant in service and held for future use 7,370,852 7,265,604 Less accumulated depreciation and amortization 2,941,878 2,814,762 ---------- ---------- Total 4,428,974 4,450,842 Construction work in progress 247,910 228,643 Nuclear fuel, net of amortization 50,446 51,078 ---------- ---------- Net utility plant 4,727,330 4,730,563 ---------- ---------- Deferred Debits Regulatory asset for income taxes 373,417 400,795 Rate synchronization cost deferral 276,055 303,660 Other deferred debits 363,912 365,146 ---------- ---------- Total deferred debits 1,013,384 1,069,601 ---------- ---------- Total Assets $6,804,221 $6,824,546 ========== ========== See Notes to Condensed Consolidated Financial Statements.
-7- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED BALANCE SHEETS LIABILITIES AND EQUITY (Thousands of Dollars) June 30, December 31, 1999 1998 (Unaudited) ---------- ---------- Current Liabilities Accounts payable $ 127,791 $ 155,800 Accrued taxes 158,195 62,520 Accrued interest 32,972 31,866 Dividends payable 27,552 -- Short-term borrowings 223,950 178,830 Current maturities of long-term debt 17,810 168,045 Customer deposits 25,943 28,510 Other current liabilities 5,806 14,632 ---------- ---------- Total current liabilities 620,019 640,203 ---------- ---------- Long-Term Debt Less Current Maturities 2,164,459 2,048,961 ---------- ---------- Deferred Credits and Other Deferred income taxes 1,319,340 1,343,536 Deferred investment tax credit 19,672 27,345 Unamortized gain - sale of utility plant 75,499 77,787 Other 435,351 428,122 ---------- ---------- Total deferred credits and other 1,849,862 1,876,790 ---------- ---------- Commitments and contingencies (Notes 5, 6, 9 and 10) Minority Interests Non-redeemable preferred stock of APS -- 85,840 ---------- ---------- Redeemable preferred stock of APS -- 9,401 ---------- ---------- Common Stock Equity Common stock, no par value 1,540,437 1,550,643 Retained earnings 629,444 612,708 ---------- ---------- Total common stock equity 2,169,881 2,163,351 ---------- ---------- Total Liabilities and Equity $6,804,221 $6,824,546 ========== ========== See Notes to Condensed Consolidated Financial Statements.
-8- PINNACLE WEST CAPITAL CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (THOUSANDS OF DOLLARS) Six Months Ended June 30, ---------------------- 1999 1998 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 99,392 $ 80,083 Items not requiring cash Depreciation and amortization 194,293 186,415 Nuclear fuel amortization 15,673 16,580 Deferred income taxes--net (21,477) 5,645 Deferred investment tax credit (7,673) (7,895) Other--net 1,096 782 Changes in current assets and liabilities Customer and other receivables--net 48,175 12,544 Accrued utility revenues (30,306) (8,363) Materials, supplies and fossil fuel (5,653) (8,912) Other current assets (8,329) (5,314) Accounts payable (25,465) (12,438) Accrued taxes 95,675 (8,081) Accrued interest 1,106 (349) Other current liabilities (5,307) 5,339 Decrease (increase) in land held (4,642) 15,084 Other--net (16,382) (7,364) --------- --------- Net Cash Flow Provided By Operating Activities 330,176 263,756 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (153,730) (144,580) Capitalized interest (8,263) (9,530) Other--net 1,282 15,485 --------- --------- Net Cash Flow Used For Investing Activities (160,711) (138,625) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES Issuance of long-term debt 193,691 99,375 Short-term borrowings--net 45,120 82,735 Dividends paid on common stock (55,101) (50,878) Repayment of long-term debt (235,755) (220,782) Redemption of preferred stock (96,499) (31,209) Other--net (8,948) (215) --------- --------- Net Cash Flow Used For Financing Activities (157,492) (120,974) --------- --------- Net Cash Flow 11,973 4,157 Cash and Cash Equivalents at Beginning of Period 20,538 27,484 ========= ========= Cash and Cash Equivalents at End of Period $ 32,511 $ 31,641 ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest, net of amounts capitalized $ 68,341 $ 72,863 Income taxes $ 940 $ 64,820 See Notes to Condensed Consolidated Financial Statements.
-9- 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, Suncor, El Dorado, and APS Energy Services. All significant intercompany balances 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. 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 1998 10-K. 3. Weather conditions can have a significant impact on APS' results for interim periods. For this and other reasons, 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 six months ended June 30, 1999. 5. Regulatory Accounting APS prepares its 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. APS' existing regulatory orders and the current regulatory environment support its accounting practices related to regulatory assets, which amounted to about $850 million at June 30, 1999. Under the 1996 regulatory agreement (see Note 7), the ACC accelerated the amortization of substantially all of APS' regulatory assets to an eight-year period that will end June 30, 2004. 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.
-10- Although rules have been proposed for the transition of generation services to competition, there are many unresolved issues. APS continues to apply SFAS No. 71 to its generation operations. If rate recovery of regulatory assets is no longer probable, whether due to competition or regulatory action, APS would be required to write off the remaining balance as an extraordinary charge to expense. See Note 6 for a discussion of a proposed settlement agreement which, if approved, would result in the discontinuation of SFAS No. 71 for generation operations. 6. Regulatory Matters -- Electric Industry Restructuring STATE PROPOSED SETTLEMENT AGREEMENT As of May 14, 1999, APS entered into a comprehensive Settlement Agreement with various other parties, including representatives of major consumer groups, related to the implementation of retail electric competition. Hearings before the ACC on the Settlement Agreement ended in July 1999, and a final ACC order, which is a condition to the agreement's effectiveness, has not yet been issued. By the terms of the Settlement Agreement, unless ACC approval has been obtained on or before August 1, 1999, each party has the right to unilaterally withdraw from the Settlement Agreement. To date, no party has elected to withdraw. The following are the major provisions of the Settlement Agreement: * APS will reduce rates for standard offer service for customers with loads less than 3 megawatts in a series of annual rate reductions of 1.5% beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction includes the July 1, 1999 retail price decrease related to the 1996 regulatory agreement. See Note 7. For customers having loads 3 megawatts or greater, standard offer rates will be reduced in annual increments that total 5% through 2002. * Unbundled rates being charged by APS for competitive direct access service (for example, distribution services) will become effective as of July 1, 1999, and will be subject to annual reductions, that vary by rate class, through 2003. * There will be a moratorium on retail rate changes for standard offer and unbundled competitive direct access rates until July 1, 2004, except for the price reductions described above and certain other limited circumstances. * 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 APS' "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.
-11- * APS' distribution system will be open for retail access upon approval of the Settlement Agreement. Customers will be eligible for retail access in accordance with the phase-in program expected to be ultimately adopted by the ACC under the electric competition rules when such rules become effective, with an additional 140 megawatts being made available to eligible non-residential customers. Unless subject to judicial or regulatory restraint, APS will open its distribution system to retail access for all customers on January 1, 2001. * APS is currently recovering substantially all of its regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. See Note 7. In addition, the 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 Settlement Agreement provides that APS 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. * APS will form a separate corporate affiliate or affiliates and transfer thereto its generating assets and competitive services by December 31, 2002. * Upon final approval of the Settlement Agreement by the ACC in an order no longer subject to judicial review, APS will move to dismiss all of its litigation pending against the ACC as of the date of the Settlement Agreement. Upon final ACC order, APS will discontinue the application of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," for its generation operations. This means that regulatory assets, unless reestablished as recoverable through ongoing regulated cash flows, are to be eliminated and the generation assets must be tested for impairment. The regulatory disallowance, which removes $234 million pre-tax ($183 million net present value) from ongoing regulatory cash flows, will be recorded as a net reduction of regulatory assets. This reduction will be reported as an extraordinary charge on the income statement. The regulatory assets to be recovered under this Settlement Agreement would be amortized as follows: (Millions) 1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total - -------- -------- -------- -------- -------- -------- -------- $164 $158 $145 $115 $86 $18 $686
-12- PROPOSED RETAIL ELECTRIC COMPETITION RULES In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition in Arizona. The ACC adopted certain modifications to these rules on August 10, 1998, and on December 11, 1998, the ACC adopted the amended rules, without any modifications that would have a significant impact on APS, on a permanent basis. We believe that certain provisions of the 1996 ACC rules and the amended rules are deficient and APS has filed lawsuits to protect its legal rights regarding the 1996 rules and the amended rules. These lawsuits are pending but two related cases filed by other utilities have been partially decided in a manner adverse to those utilities' positions. On January 11, 1999, the ACC issued an order which stayed the amended rules, granted reconsideration of the decision to make the rules permanent, and directed the hearing division of the ACC to establish a procedural order for further action on these rules. The order also granted waivers from compliance with the rules for APS, and all affected utilities. On February 5, 1999, the ACC Hearing Division issued recommendations for changes to the amended rules. The recommended changes to the amended rules were further modified by a Procedural Order of the ACC Hearing Division dated March 12, 1999. On April 14, 1999, the ACC voted to notice, for further rulemaking, the Hearing Division's recommended changes, with certain exceptions (the "Proposed Rules"). The Proposed Rules approved by the ACC for further rulemaking include the following major provisions: * They would apply to virtually all Arizona electric utilities regulated by the ACC, including APS. * The Proposed Rules require each affected utility, including APS, to make available at least 20% of its 1995 system retail peak demand for competitive generation supply beginning when the ACC makes a final decision on each utility's stranded costs and unbundled rates (Final Decision Date) or January 1, 2001, whichever is earlier, and 100% beginning January 1, 2001. * 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. Customers with single premise loads of 40 kilowatts or greater may aggregate loads to meet this one megawatt requirement. * When effective, residential customers will be phased in at 1 1/4% 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.
-13- * Affected utilities must file ACC tariffs with separate pricing for electric services provided for noncompetitive services. * The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs (see "Stranded Costs" below). * Absent an ACC waiver, prior to January 1, 2001, each affected utility must transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate. The Proposed Rules will not become final and effective until approved by the ACC following formal rulemaking proceedings under Arizona law. In compliance with statutory procedural requirements, ACC oral proceedings on the matter were held in June 1999, and a final order has not yet been issued. We cannot currently predict when or if the Proposed Rules will become effective, when or if the stay of the amended rules will be lifted, or when retail electric competition will be introduced in Arizona. See "Proposed Settlement Agreement" above for discussion of APS' proposals regarding the introduction of retail electric competition in Arizona. STRANDED COSTS On June 22, 1998, the ACC issued an Order on stranded cost determination and recovery. APS believes that certain provisions of the stranded cost order are deficient and in August 1998, APS filed two lawsuits to protect its legal rights relating to the order. On February 5, 1999, the ACC Hearing Division issued recommended changes to the June 1998 stranded cost order. These recommended changes were further amended by an ACC Procedural Order dated March 12, 1999. On April 14, 1999, the ACC voted to adopt the Hearing Division's changes to the June 1998 stranded cost order. The amended stranded cost order became effective on April 27, 1999, and allows each affected utility to choose from any one of five options for the recovery of stranded costs: * Net Revenues Lost Methodology is the difference between generation revenues under traditional regulation and generation revenues under competition. This option provides for declining recovery percentages for stranded costs over a five-year recovery period. Regulatory assets are to be fully recovered under their presently authorized amortization schedule. In accordance with a 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of APS' regulatory assets to an eight-year period that ends June 30, 2004. * Divestiture/Auction Methodology allows a utility to divest all or substantially all of its generating assets, including regulatory assets associated with generation, in order to collect 100 percent of the difference between net sales price and book value of generating assets divested over a ten-year period, with no return on the unamortized balance.
-14- * Financial Integrity Methodology allows a utility "sufficient revenues to meet minimum financial ratios" for a period of ten years. * Settlement Methodology allows a settlement to be agreed upon by the ACC and a utility. * Any combination of the above, if shown to be in the best interests of all affected parties. See "Proposed Settlement Agreement" above, for a discussion of the methodology APS proposed. LEGISLATIVE INITIATIVES An Arizona joint legislative committee studied electric utility industry restructuring issues in 1996 and 1997. In conjunction with that study, the Arizona legislative counsel prepared memoranda in late 1997 related to the legal authority of the ACC to deregulate the Arizona electric utility industry. The memoranda raise a question as to the degree to which the ACC may, under the Arizona Constitution, deregulate any portion of the electric utility industry and allow rates to be determined by market forces. This latter issue has been subsequently decided by lower courts in favor of the ACC in four separate lawsuits, two of which are unrelated. 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. In addition, the Arizona legislature will review and make recommendations for the 1999 legislative session on certain competitive issues.
-15- GENERAL Until the manner of implementation of competition, including addressing stranded costs, is determined, we cannot accurately predict the impact of full retail competition on our financial position, cash flows, or results of operation. 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. See "Proposed Settlement Agreement" above. FEDERAL The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. APS does not expect these rules to have a material impact on its financial statements. Several electric utility industry restructuring bills have been introduced during the 106th Congress. 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 substantial restructuring of the electric utility industry can occur. 7. 1996 Regulatory Agreement In April 1996, the ACC approved a regulatory agreement between the ACC Staff and APS. The major provisions of this agreement are: * An annual rate reduction of approximately $48.5 million ($29 million after income taxes), or 3.4% on average for all customers except certain contract customers, effective July 1, 1996. * Recovery of substantially all of APS' present regulatory assets through accelerated amortization over an eight-year period that will end June 30, 2004, increasing annual amortization by approximately $120 million ($72 million after income taxes). * A formula for sharing future cost savings between customers and shareholders (price reduction formula), referencing a return on equity (as defined) of 11.25%. * A moratorium on filing for permanent rate changes prior to July 2, 1999, except under the price reduction formula and under certain other limited circumstances. * Infusion of $200 million of common equity into APS by the parent company, in annual payments of $50 million starting in 1996. Based on the price reduction formula, the ACC approved retail price decreases of approximately $17.6 million ($10.5 million after income taxes), or 1.2%, effective July 1, 1997, and approximately $17 million ($10 million after income taxes), or 1.1%, effective July 1, 1998. In May 1999, APS filed with the ACC for another retail price decrease of approximately $10.8 million annually ($6.5 million after income taxes), which would become effective as of July 1, 1999. The amount and timing of the price decrease are subject to ACC approval. This will be the last price decrease under the 1996 regulatory
-16- agreement and will be included in the first rate reduction under the proposed Settlement Agreement discussed in Note 6. See "Proposed Settlement Agreement" above for a discussion of the price decrease. 8. Agreement with Salt River Project On April 25, 1998, APS entered into a Memorandum of Agreement with Salt River Project in anticipation of, and to facilitate, the opening of the Arizona electric industry. The Agreement contains the following major components: * Both parties amended the Territorial Agreement to remove any barriers in that agreement to the provision of competitive electricity supply and non-distribution services. * Both parties would amend the Power Coordination Agreement to lower the price that APS will pay Salt River Project for purchased power by approximately $17 million (pretax) during the first full year that the Agreement is effective and by lesser annual amounts during the next seven years. * Both parties agreed on certain legislative positions regarding electric utility restructuring at the state and federal level. Certain provisions of the Agreement (including those relating to the amendments of the Territorial Agreement and the Power Coordination Agreement) are affected by the timing of the introduction of competition. See Note 6. On February 18, 1999, the ACC approved the Agreement. 9. 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 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. 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
-17- insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. 10. Accounting Matters In June 1998 the Financial Accounting Standards Board (FASB) issued 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. The standard also provides specific guidance for accounting for derivatives designated as hedging instruments. The statement was to have been effective for us in 2000; however, the FASB has moved the effective date to 2001. We are currently evaluating what impact this standard will have on our financial statements. 11. Memorandum of Understanding with Calpine Corporation On April 23, 1999, we entered into a memorandum of understanding with Calpine Corporation, an independent power producer located in San Jose, California, for a potential $220 million, 500 megawatt expansion at the site of APS' West Phoenix Power Plant. We entered into a further memorandum of understanding with Calpine dated as of August 4, 1999, relating to the timing of the definitive agreements and the operation of the joint project. The joint project is the second phase of a potential 750 megawatt expansion at West Phoenix, the first phase of which includes the installation of a 120 megawatt combined cycle unit, the cost of which is expected to be approximately $60 million, although that amount is currently subject to negotiation. Assuming approvals are granted, construction is scheduled to begin in mid-2000, with commercial operation of the first phase in mid-2001 and the second phase in early 2002.
-18- PINNACLE WEST CAPITAL CORPORATION 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 for Pinnacle West and our subsidiaries: APS, SunCor, El Dorado, and APS Energy Services, including: * the changes in our earnings for the periods presented * the factors impacting our business, including competition and electric industry restructuring * the effects of regulatory agreements on our results * our capital needs and resources and * Year 2000 technology issues. We suggest this section be read along with the 1998 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. These Notes add further details to the discussion. OPERATING RESULTS OPERATING RESULTS - THREE-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH THREE-MONTH PERIOD ENDED JUNE 30, 1998 Consolidated net income for the three months ended June 30, 1999 was $68.7 million compared with $49.0 million for the same period in the prior year. Net income increased in the three-month comparison primarily because of higher earnings at APS. APS' earnings increased $19.8 million in the three-month comparison primarily because of the effects of warmer weather, an increase in customers, and increased contributions from power marketing and trading activities, partially offset by a retail price reduction, and higher depreciation and amortization expense. See Note 7 for information on the price reduction. Electric operating revenues increased $70 million because of: * increased power marketing and trading revenues ($36 million) * the effects of warmer weather ($21 million) and * increases in the number of customers ($17 million). As mentioned above, these positive factors were partially offset by the effect of a reduction in retail prices ($4 million).
-19- Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted primarily from increased activity in western bulk power markets. The increase in power marketing and trading revenues was accompanied by increases in purchased power expenses. Fuel expenses increased $37 million primarily because of increased wholesale and retail sales volume and higher purchased power prices. Depreciation and amortization expense increased $4 million because APS had more plant in service. OPERATING RESULTS - SIX-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH SIX-MONTH PERIOD ENDED JUNE 30, 1998 Consolidated net income for the six months ended June 30, 1999 was $99.4 million compared with $80.1 million for the same period in the prior year. Net income increased in the six-month comparison primarily because of higher earnings at APS, partially offset by lower earnings at El Dorado. APS earnings increased $23.5 million in the six-month comparison primarily because of an increase in customers, increased contributions from power marketing and trading activities, and the effects of warmer weather, partially offset by a retail price reduction, and higher depreciation and amortization expense. See Note 7 for information on the price reduction. Electric operating revenues increased $103 million because of: * increased power marketing and trading revenues ($70 million) * increases in the number of customers ($29 million) * the effects of warmer weather ($10 million) and * miscellaneous factors ($2 million). As mentioned above, these positive factors were partially offset by the effect of a reduction in retail prices ($8 million). Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted from increased activity in western bulk power markets. The increase in power marketing and trading revenues was accompanied by increases in purchased power expenses. Fuel expenses increased $62 million primarily because of increased wholesale and retail sales volume and higher purchased power prices. Depreciation and amortization expense increased $8 million because APS had more plant in service. El Dorado's earnings decreased $4 million because of investment sales in 1998.
-20- OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED JUNE 30, 1999 COMPARED WITH TWELVE-MONTH PERIOD ENDED JUNE 30, 1998 Consolidated net income for the twelve months ended June 30, 1999 was $262.2 million compared with $223.4 million for the same period in the prior year. Net income increased in the twelve-month comparison primarily because of higher earnings at APS and lower financing costs at the parent, partially offset by lower contributions to earnings by the other subsidiaries. APS earnings increased $42.9 million in the twelve-month comparison primarily because of an increase in customers, increased contributions from power marketing and trading activities, the effects of warmer weather, and lower financing costs. In the comparison, these positive factors more than offset the effects of two fuel-related settlements recorded in the third quarter of 1997, a retail price reduction that became effective July 1, 1998, and higher depreciation and amortization expense. See Note 7 for additional information about the price reduction. Operating revenues increased $247 million primarily because of: * increased power marketing and trading revenues ($164 million) * increases in the number of customers and the average amount of electricity used by customers ($79 million) * the effects of warmer weather ($15 million) and * miscellaneous factors ($7 million). As mentioned above, these positive factors were partially offset by the effect of a reduction in retail prices ($18 million). Power marketing and trading activities are predominantly short-term opportunity wholesale sales. The increase in power marketing revenues resulted from increased activity in Western bulk power markets, higher prices, and increased sales to large customers in California. The increase in power marketing and trading revenues was accompanied by increases in purchased power expenses. Fuel expense increased $178 million primarily because of increased wholesale and retail sales volumes, the effects of two fuel-related settlements in the third quarter of 1997, and higher purchased power prices. The settlements increased pretax earnings in the twelve months ended June 30, 1998 by approximately $21 million. The income statement reflects these settlements as reductions in fuel expense and as other income. Depreciation and amortization expense increased $17 million because APS had more plant in service. APS decreased its financing costs by $10 million primarily because of lower amounts of outstanding debt and preferred stock and lower interest rates.
-21- Parent company financing costs decreased $7 million as we paid down debt and took advantage of lower interest rates. El Dorado's earnings decreased $5 million in the twelve-month period because of investment sales in 1998 and 1997. APS Energy Services, which was incorporated in late 1998, reported a loss of $3 million for the twelve-month period. OTHER INCOME As part of a 1994 rate settlement with the ACC, APS accelerated amortization of substantially all deferred ITCs over a five-year period that ends on December 31, 1999. The amortization of ITCs decreases annual consolidated income tax expense by approximately $24 million. Beginning in 2000, no further benefits will be reflected in income tax expense. LIQUIDITY AND CAPITAL RESOURCES PARENT COMPANY 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 1998 10-K. During the six-months ended June 30, 1999, the parent company redeemed approximately $19 million of its long-term debt with cash from operations and proceeds from long-term borrowings. As a result of the 1996 regulatory agreement (see Note 7), the parent company has invested $50 million in APS in 1996, 1997 and 1998 and will make the final investment of $50 million in 1999. On April 23, 1999, we entered into a memorandum of understanding with Calpine Corporation, an independent power producer located in San Jose, California, for a potential $220 million, 500 megawatt expansion at the site of APS' West Phoenix Power Plant. We entered into a further memorandum of understanding with Calpine dated as of August 4, 1999, relating to the timing of the definitive agreements and the operation of the joint project. The joint project is the second phase of a potential 750 megawatt expansion at West Phoenix, the first phase of which includes the installation of a 120 megawatt combined cycle unit, the cost of which is expected to be approximately $60 million, although that amount is currently subject to negotiation. Assuming approvals are granted, construction is scheduled to begin in mid-2000, with commercial operations of the first phase in mid-2001 and of the second phase in early 2002. We are also considering additional expansion over the next several years, which may result in additional expenditures. We currently believe that there will be additional
-22- opportunities to expand our investment in generating assets in the next five years. It is expected that these and other generating assets would be organized in a non-regulated subsidiary under the parent company. The Board declared a quarterly dividend of 32.5 cents per share of common stock, payable September 1, 1999 to shareholders of record on August 2, 1999, totaling approximately $27.6 million. APS For the six months ended June 30, 1999, APS incurred approximately $154 million in capital expenditures, which is approximately 47% of the most recently estimated 1999 capital expenditures. APS' projected capital expenditures for the next three years are: 1999, $328 million; 2000, $353 million; and 2001, $343 million. These amounts include about $30 - $35 million each year for nuclear fuel expenditures. APS' long-term debt and preferred stock redemption requirements and payment obligations on a capitalized lease for the next three years are: 1999, $387 million; 2000, $115 million; and 2001, $2 million. During the six months ended June 30, 1999, APS redeemed approximately $216 million of its long-term debt and all $96 million (including premiums) of its preferred stock with cash from operations and long-term and short-term debt. In February 1999, APS issued $125 million of unsecured long-term debt. As a result of the 1996 regulatory agreement (see Note 7), Pinnacle West invested $50 million in APS in 1996, 1997, and 1998 and will make the final investment of $50 million in 1999. Although provisions in APS' first mortgage bond indenture, articles of incorporation, and ACC financing orders establish maximum amounts of additional first mortgage bonds that we may issue, APS does not expect any of these provisions to limit its ability to meet its capital requirements. YEAR 2000 READINESS DISCLOSURE OVERVIEW As the year 2000 approaches, many companies face problems because many computer systems and equipment will not properly recognize calendar dates beginning with the year 2000. We are addressing the Year 2000 issue as described below. APS initiated a comprehensive company-wide Year 2000 program during 1997 to review and resolve all Year 2000 issues in mission critical systems (systems and equipment that are key to the power production, delivery, health, and safety functions) in a timely manner to ensure the reliability of electric service to its customers. This included a company-wide awareness program of the Year 2000 issue. APS has an internal audit/quality review team that is periodically reviewing the individual Year 2000 projects and their Year 2000 readiness.
-23- The following chart shows Year 2000 readiness of our mission critical systems as of June 30, 1999: Inventory Assessment Remediation & Testing --------- ---------- --------------------- APS 100% 100% 100% Pinnacle West and other subsidiaries (excluding APS) 100% 100% 95%(1) (1) Estimated to be at 100% by September 30, 1999. DISCUSSION APS has been actively implementing and replacing systems and technology since 1995 for general business reasons unrelated to the Year 2000, and these actions have resulted in substantially all of its major information technology (IT) systems becoming Year 2000 ready. The major IT systems that were, and are being, implemented and replaced include the following: * Work Management * Materials Management * Energy Management System * Payroll * Financial * Human Resources * Trouble Call Management System * Computer and Communications Network Upgrades * Geographic Information System * Customer Information System and * Palo Verde Site Work Management System. We and our subsidiaries have made, and will continue to make, certain modifications to computer hardware, software, and application systems, including IT and non-IT systems, in an effort to ensure they are capable of handling changing business needs, including dates in the year 2000 and thereafter. In addition, other APS IT systems and non-IT systems, including embedded technology and real-time process control systems, are being analyzed for potential modifications. Pinnacle West and its subsidiaries have inventoried and assessed essentially all mission critical IT and non-IT systems and equipment. APS is 100% complete and Pinnacle West and its other subsidiaries are 95% complete with the remediation and testing of these systems. APS notified the North American Electric Reliability Council (NERC) on June 30, 1999, that its mission critical systems are ready for date changes associated with the Year 2000, in accordance with NERC's recommended criteria. APS also notified the Nuclear Regulatory Commission (NRC) that Palo Verde is "Y2K Ready," which means that Palo Verde has followed a prescribed program to identify
-24- and resolve Year 2000 issues so that the plant can operate reliably while meeting commitments. As previously reported, APS expected remediation and testing to be completed by June 30, 1999, for all mission critical systems, except for (i) Palo Verde Unit 1 systems and (ii) the continuous emissions monitoring systems (CEMS) for four of its fossil plants. See "Year 2000 Readiness Disclosure" in Part I, Item 2 of the March 10-Q. However, as of June 30, 1999, remediation and testing was completed for all mission critical systems, including Palo Verde Unit 1, but excluding CEMS, which have been removed from the mission critical systems list because the failure of the system would not lead to an unplanned shutdown of generation. This is based on NERC's June 14, 1999 clarifying pronouncement on exception reporting. APS currently expects the CEMS for the four fossil plants to be Y2K Ready no later than the fourth quarter 1999. APS currently estimates that it will spend approximately $5 million relating to Year 2000 issues, about $4.5 million of which has been spent to date. This includes an estimated allocation of payroll costs for APS employees working on Year 2000 issues, and costs for consultants, hardware, and software. We do not separately track other internal costs. This does not include any expenditures incurred since 1995 to implement and replace systems for reasons unrelated to the Year 2000, as discussed above. Our cost to address the Year 2000 issue is charged to operating expenses as incurred and has not had, and is not expected to have, a material adverse effect on our financial position, cash flows, or results of operations. We expect to fund this cost with available cash balances and cash provided by operations. Pinnacle West and its subsidiaries are communicating with their significant suppliers, business partners, other utilities, and large customers to determine the extent to which they may be affected by these third parties' plans to remediate their own Year 2000 issues in a timely manner. These companies have been interfacing with suppliers of systems, services, and materials in order to assess whether their schedules for analysis and remediation of Year 2000 issues are timely and to assess their ability to continue to supply required services and materials. APS has also been working with NERC through the Western Systems Coordinating Council (WSCC) to develop operational plans for stable grid operation that will be utilized by APS and other utilities in the western United States. APS' operational plans are complete. However, APS cannot currently predict the effect on APS if the systems of these other companies are not Year 2000 ready. We currently expect that our most reasonably likely worst case Year 2000 scenario would be intermittent loss of power to APS customers, similar to an outage during a severe weather disturbance. In this situation, APS would restore power as soon as possible by, among other things, re-routing power flows. We do not currently expect that this scenario would have a material adverse effect on our financial position, cash flows, or results of operations.
-25- Pinnacle West and its subsidiaries have developed their own contingency plans to handle Year 2000 issues, including the most reasonably likely worst case scenario discussed above. These plans were completed June 30, 1999. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See Note 5 for a discussion of regulatory accounting. See Note 6 for a discussion of a proposed Settlement Agreement related to the implementation of retail electric competition. See Note 8 for a discussion of a proposed amendment to a Power Coordination Agreement with Salt River Project that APS estimates would reduce its pretax costs for purchased power by approximately $17 million during the first full year that the amendment is effective and by lesser annual amounts during the next seven years. RATE MATTERS See Note 7 for a discussion of a proposed price reduction that would become effective as of July 1, 1999. See Note 6 for a discussion of a proposed Settlement Agreement that would, among other things, result in rate reductions over a four year period ending July 1, 2003. FORWARD-LOOKING STATEMENTS The above discussion contains forward-looking statements that involve risks and uncertainties. Words such as "estimates," "expects," "anticipates," "plans," "believes," "projects," and similar expressions identify forward-looking statements. These risks and uncertainties include, but are not limited to, the ongoing restructuring of the electric industry; the outcome of the regulatory proceedings relating to the restructuring; regulatory, tax, and environmental legislation; the ability of APS to successfully compete outside its traditional regulated markets; regional economic conditions, which could affect customer growth; the cost of debt and equity capital; weather variations affecting customer usage; technological developments in the electric industry; the successful completion of a large-scale construction project; Year 2000 issues; and the strength of the real estate market. 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 interest rates, commodity prices, and investments held by the nuclear decommissioning trust fund. Our major financial market risk exposure is changing interest rates. 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 and floating rate debt. The nuclear decommissioning fund also
-26- has risks associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in rates. APS is exposed to the impact of market fluctuations in the price and distribution costs of electricity, natural gas, coal, and emissions and therefore employs established procedures to manage its 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 its overall risk management program, APS enters into these derivative transactions for trading and to hedge certain natural gas in storage as well as purchases and sales of electricity, fuels, and emissions. APS measures the price risk in its commodity derivative portfolio on a daily basis utilizing market sensitivity based modeling to understand expected and potential single day favorable or unfavorable impacts to income before tax. The model results are monitored daily to ensure compliance against thresholds on a commodity and portfolio basis. As of June 30, 1999, a hypothetical adverse price movement of 10% in the market price of APS' commodity derivative portfolio would decrease the fair market value of these contracts by approximately $8 million. This analysis does not include the favorable impact this same hypothetical price move would have on the underlying position being hedged with the commodity derivative portfolio. APS is exposed to credit losses in the event of non-performance or non-payment by counterparties. APS uses a credit management process to assess and monitor the financial exposure of counterparties. APS does not expect counterparty defaults to materially impact its financial condition, results of operations, or net cash flows.
PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS In June 1999, the Navajo Nation served Salt River Project with a lawsuit naming Salt River Project, several Peabody Coal Company entities ("Peabody"), Southern California Edison Company, and other defendants, and citing various claims in connection with the renegotiations of the coal royalty and lease agreements under which Peabody mines coal for the Navajo and Mohave Generating Stations. THE NAVAJO NATION V. PEABODY HOLDING COMPANY, INC., ET AL., United States District Court for the District of Columbia, No. CA-99-0469-EGS. APS is a 14% owner of Navajo Generating Station, which Salt River Project operates. The suit alleges, among other things, that the defendants obtained a favorable coal royalty rate by improperly influencing the outcome of a federal administrative process under which the royalty rate was to be adjusted. The suit seeks $600 million in damages, treble damages, punitive damages of not less than $1 billion, and the ejection of defendants "from all possessory interests and Navajo Tribal lands" arising out of the [primary coal lease]. Salt River Project has advised APS that it denies all charges and will vigorously defend itself. Because the litigation is in preliminary stages, APS cannot currently predict the outcome of this matter. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS At our annual Meeting of Shareholders held on May 19, 1999 the following shareholder proposal was submitted to shareholders: Abstentions Votes Votes and Broker For Against Non Votes ----- ------- ----------- Proposal that Pinnacle 2,413,519 63,160,240 2,955,431 West refuse to use plutonium (MOX) fuel and refuse to generate tritium In addition, at the same annual meeting, the following persons were elected Class II Directors with a term to expire at the 2002 annual meeting of shareholders: Abstentions Votes Votes and Broker For Withheld Non Votes ----- ------- ----------- Edward N. Basha 78,205,297 1,528,855 N/A Michael L. Gallagher 78,246,095 1,488,057 N/A William J. Post 78,396,955 1,337,197 N/A
-28- 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 APS' construction and financing programs. 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 proposed settlement agreement with the ACC. ENVIRONMENTAL MATTERS As previously reported, in July 1997, EPA promulgated final national ambient air quality standards for ozone and coarse and fine particulate matter. See "Environmental Matters - EPA Environmental Regulation - Clear Air Act" in Part I, Item 1 of the 1998 10-K. These standards were challenged and the court determined that EPA's promulgation of the standards violated the constitutional prohibition on delegation of legislative power. The court remanded the ozone standard, vacated the coarse particulate matter standard, and invited the parties to brief the court on vacating or remanding the fine particulate matter standard. APS cannot currently predict EPA's response to this decision. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit No. Description - ----------- ----------- 10.1(a) Key Executive Employment and Severance Agreement between Pinnacle West and certain executive officers of Pinnacle West and its subsidiaries 27.1 Financial Data Schedule - ---------- (a) Additional agreements, substantially identical in all material respects to this Exhibit have been entered into with additional officers of Pinnacle West and its subsidiaries. Although such additional documents may differ in other respects (such as dollar amounts and dates of execution), there are no material details in which such agreements differ from this Exhibit.
-29- 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: <TABLE> <CAPTION> EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(b) 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 3.1 to the Company's 1995 1-8962 4-1-96 February 21, 1996 Form 10-K Report </TABLE> (b) Reports on Form 8-K During the quarter ended June 30, 1999, and the period from July 1 through August 16, 1999, we filed the following reports on Form 8-K: Report dated March 22, 1999 relating to Pinnacle West's amended and restated stockholder rights plan, effective March 26, 1999. Report dated May 14, 1999 regarding the settlement agreement between APS and various other parties, including representatives of major consumer groups, related to the implementation of retail electric competition. - ---------- (b) Reports filed under File No. 1-8962 were filed in the office of the Securities and Exchange Commission located in Washington, D.C.
-30- 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: August 16, 1999 By: George A. Schreiber, Jr. ------------------------------------ George A. Schreiber, Jr. President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report)