-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, S4tDyuKqlRvyR/HieHOdzf8ZfytXBcz63nPDsfKYJrHLr08cOq65MKCXeSktc9SG ju7vgk43Z/vG3rTLgdeXTQ== 0000950147-98-000929.txt : 19981118 0000950147-98-000929.hdr.sgml : 19981118 ACCESSION NUMBER: 0000950147-98-000929 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19980930 FILED AS OF DATE: 19981116 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ARIZONA PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000007286 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 860011170 STATE OF INCORPORATION: AZ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-04473 FILM NUMBER: 98749883 BUSINESS ADDRESS: STREET 1: 400 N FIFTH ST STREET 2: P O BOX 53999 CITY: PHOENIX STATE: AZ ZIP: 85004 BUSINESS PHONE: 6022501000 10-Q 1 QUARTERLY REPORT FORM 10-Q Securities and Exchange Commission Washington, D.C. 20549 [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended SEPTEMBER 30, 1998 ----------------------------- OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to ------------- ------------- Commission file number 1-4473 ----------- ARIZONA PUBLIC SERVICE COMPANY ------------------------------------------------------ (Exact name of registrant as specified in its charter) ARIZONA 86-0011170 - ------------------------------- ------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 400 NORTH FIFTH STREET, P.O. BOX 53999, PHOENIX, ARIZONA 85072-3999 - -------------------------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (602) 250-1000 - -------------------------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Number of shares of common stock, $2.50 par value, outstanding as of November 13, 1998: 71,264,947 GLOSSARY ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission Company - Arizona Public Service Company 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" FERC - Federal Energy Regulatory Commission ITC - Investment tax credit 1997 10-K - Arizona Public Service Company Annual Report on Form 10-K for the fiscal year ended December 31, 1997 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" SFAS No. 131 - Statement of Financial Accounting Standards No. 131, "Disclosures about Segments of an Enterprise and Related Information" 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 TEP - Tucson Electric Power Company Territorial Agreement - 1955 agreement between the Company and Salt River Project that has provided exclusive retail service territories in Arizona as against each other -2- PART I - FINANCIAL INFORMATION ------------------------------ ITEM 1. FINANCIAL STATEMENTS ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited) Three Months Ended September 30, ----------------------- 1998 1997 --------- --------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES .......................... $ 740,734 $ 632,821 --------- --------- FUEL EXPENSES: Fuel for electric generation ....................... 74,112 48,379 Purchased power .................................... 178,587 110,151 --------- --------- Total ........................................... 252,699 158,530 --------- --------- OPERATING REVENUES LESS FUEL EXPENSES ................ 488,035 474,291 --------- --------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses .................................... 110,259 110,102 Depreciation and amortization ...................... 94,284 90,874 Income taxes ....................................... 98,411 92,195 Other taxes ........................................ 30,002 30,228 --------- --------- Total ........................................... 332,956 323,399 --------- --------- OPERATING INCOME ..................................... 155,079 150,892 --------- --------- OTHER INCOME (DEDUCTIONS): Other - net ........................................ (2,120) 445 Income taxes ....................................... 14,271 14,052 --------- --------- Total ........................................... 12,151 14,497 --------- --------- INCOME BEFORE INTEREST DEDUCTIONS .................... 167,230 165,389 --------- --------- INTEREST DEDUCTIONS: Interest on long-term debt ......................... 33,906 35,699 Interest on short-term borrowings .................. 2,359 2,163 Debt discount, premium and expense ................. 1,878 1,825 Capitalized interest ............................... (4,106) (3,997) --------- --------- Total ........................................... 34,037 35,690 --------- --------- NET INCOME ........................................... 133,193 129,699 PREFERRED STOCK DIVIDEND REQUIREMENTS ................ 2,347 2,984 --------- --------- EARNINGS FOR COMMON STOCK ............................ $ 130,846 $ 126,715 ========= ========= See Notes to Condensed Financial Statements. -3- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited) Nine Months Ended September 30, ------------------------- 1998 1997 ----------- ---------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES ........................ $1,562,872 $1,470,593 ---------- ---------- FUEL EXPENSES: Fuel for electric generation ..................... 174,874 155,127 Purchased power .................................. 247,327 188,182 ---------- ---------- Total ......................................... 422,201 343,309 ---------- ---------- OPERATING REVENUES LESS FUEL EXPENSES .............. 1,140,671 1,127,284 ---------- ---------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses................................... 309,388 287,280 Depreciation and amortization .................... 279,097 274,027 Income taxes ..................................... 162,808 164,066 Other taxes ...................................... 89,459 89,874 ---------- ---------- Total ......................................... 840,752 815,247 ---------- ---------- OPERATING INCOME ................................... 299,919 312,037 ---------- ---------- OTHER INCOME (DEDUCTIONS): Other - net ...................................... (7,035) (2,674) Income taxes ..................................... 26,214 24,942 ---------- ---------- Total ......................................... 19,179 22,268 ---------- ---------- INCOME BEFORE INTEREST DEDUCTIONS .................. 319,098 334,305 ---------- ---------- INTEREST DEDUCTIONS: Interest on long-term debt ....................... 103,249 105,390 Interest on short-term borrowings ................ 5,419 7,586 Debt discount, premium and expense ............... 5,745 5,883 Capitalized interest ............................. (12,627) (12,391) ---------- ---------- Total ......................................... 101,786 106,468 ---------- ---------- NET INCOME ......................................... 217,312 227,837 PREFERRED STOCK DIVIDEND REQUIREMENTS .............. 7,660 9,805 ---------- ---------- EARNINGS FOR COMMON STOCK .......................... $ 209,652 $ 218,032 ========== ========== See Notes to Condensed Financial Statements -4- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME ------------------------------ (Unaudited) Twelve Months Ended September 30, ------------------------- 1998 1997 ---------- ---------- (Thousands of Dollars) ELECTRIC OPERATING REVENUES ........................ $1,970,832 $1,850,047 ---------- ---------- FUEL EXPENSES: Fuel for electric generation ..................... 221,089 217,654 Purchased power .................................. 294,430 207,115 ---------- ---------- Total ......................................... 515,519 424,769 ---------- ---------- OPERATING REVENUES LESS FUEL EXPENSES .............. 1,455,313 1,425,278 ---------- ---------- OTHER OPERATING EXPENSES: Operations and maintenance excluding fuel expenses................................... 421,542 429,569 Depreciation and amortization .................... 370,741 363,625 Income taxes ..................................... 183,479 170,562 Other taxes ...................................... 119,844 117,084 ---------- ---------- Total ......................................... 1,095,606 1,080,840 ---------- ---------- OPERATING INCOME ................................... 359,707 344,438 ---------- ---------- OTHER INCOME (DEDUCTIONS): AFUDC - equity ................................... -- (411) Other - net ...................................... (14,188) (13,188) Income taxes ..................................... 32,685 40,383 ---------- ---------- Total ......................................... 18,497 26,784 ---------- ---------- INCOME BEFORE INTEREST DEDUCTIONS .................. 378,204 371,222 ---------- ---------- INTEREST DEDUCTIONS: Interest on long-term debt ....................... 138,790 142,196 Interest on short-term borrowings ................ 7,237 8,811 Debt discount, premium and expense ............... 7,653 7,915 Capitalized interest ............................. (16,444) (14,478) ---------- ---------- Total ......................................... 137,236 144,444 ---------- ---------- NET INCOME ......................................... 240,968 226,778 PREFERRED STOCK DIVIDEND REQUIREMENTS .............. 10,658 13,941 ---------- ---------- EARNINGS FOR COMMON STOCK .......................... $ 230,310 $ 212,837 ========== ========== See Notes to Condensed Financial Statements. -5- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ------------------------ ASSETS (Unaudited) September 30, December 31, 1998 1997 ------------ ----------- (Thousands of Dollars) UTILITY PLANT: Electric plant in service and held for future use.................................... $ 7,179,571 $ 7,009,059 Less accumulated depreciation and amortization ... 2,759,425 2,620,607 ----------- ----------- Total ......................................... 4,420,146 4,388,452 Construction work in progress .................... 211,758 237,492 Nuclear fuel, net of amortization ................ 55,771 51,624 ----------- ----------- Utility plant - net ........................... 4,687,675 4,677,568 ----------- ----------- INVESTMENTS AND OTHER ASSETS ..................... 186,342 164,906 ----------- ----------- CURRENT ASSETS: Cash and cash equivalents ........................ 17,687 12,552 Accounts receivable: Service customers ............................. 238,905 141,022 Other ......................................... 52,349 31,313 Allowance for doubtful accounts ............... (1,414) (1,338) Accrued utility revenues ......................... 86,153 58,559 Materials and supplies, at average cost .......... 71,896 70,634 Fossil fuel, at average cost ..................... 17,303 9,621 Deferred income taxes ............................ 3,496 3,496 Other ............................................ 27,632 24,529 ----------- ----------- Total current assets .......................... 514,007 350,388 ----------- ----------- DEFERRED DEBITS: Regulatory asset for income taxes ................ 414,491 458,369 Rate synchronization cost deferral ............... 317,463 358,871 Unamortized costs of reacquired debt ............. 56,409 63,501 Unamortized debt issue costs ..................... 15,142 15,303 Other ............................................ 260,904 242,236 ----------- ----------- Total deferred debits ......................... 1,064,409 1,138,280 ----------- ----------- TOTAL ......................................... $ 6,452,433 $ 6,331,142 =========== =========== See Notes to Condensed Financial Statements. -6- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ------------------------ LIABILITIES (Unaudited) September 30, December 31, 1998 1997 ----------- ----------- (Thousands of Dollars) CAPITALIZATION: Common stock .................................... $ 178,162 $ 178,162 Additional paid-in capital ...................... 1,143,617 1,142,364 Retained earnings ............................... 610,535 528,798 ----------- ----------- Common stock equity .......................... 1,932,314 1,849,324 Non-redeemable preferred stock .................. 123,795 142,051 Redeemable preferred stock ...................... 9,401 29,110 Long-term debt less current maturities .......... 1,871,949 1,953,162 ----------- ----------- Total capitalization ......................... 3,937,459 3,973,647 ----------- ----------- CURRENT LIABILITIES: Commercial paper ................................ 115,350 130,750 Current maturities of long-term debt ............ 154,220 104,068 Accounts payable ................................ 170,202 107,423 Accrued taxes ................................... 208,595 85,886 Accrued interest ................................ 26,489 31,660 Customer deposits ............................... 28,841 29,116 Other ........................................... 36,394 19,588 ----------- ----------- Total current liabilities .................... 740,091 508,491 ----------- ----------- DEFERRED CREDITS AND OTHER: Deferred income taxes ........................... 1,291,258 1,345,177 Deferred investment tax credit .................. 36,724 60,093 Unamortized gain - sale of utility plant ........ 78,931 82,363 Customer advances for construction .............. 29,489 29,294 Other ........................................... 338,481 332,077 ----------- ----------- Total deferred credits and other ............. 1,774,883 1,849,004 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Notes 5 and 8) TOTAL ........................................ $ 6,452,433 $ 6,331,142 =========== =========== See Notes to Condensed Financial Statements. -7- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF CASH FLOWS ---------------------------------- (Unaudited) Nine Months Ended September 30, ---------------------- 1998 1997 --------- --------- (Thousands of Dollars) Cash Flows from Operating Activities: Net Income ......................................... $ 217,312 $ 227,837 Items not requiring cash: Depreciation and amortization .................... 279,097 274,027 Nuclear fuel amortization ........................ 24,991 24,077 Deferred income taxes - net ...................... (47,749) (58,675) Deferred investment tax credit - net ............. (23,369) (24,091) Changes in certain current assets and liabilities: Accounts receivable - net ........................ (118,843) (84,769) Accrued utility revenues ......................... (27,594) (26,597) Materials, supplies and fossil fuel .............. (8,944) 2,077 Other current assets ............................. (3,103) (4,541) Accounts payable ................................. 61,611 23,270 Accrued taxes .................................... 122,709 93,215 Accrued interest ................................. (5,171) (13,279) Other current liabilities ........................ 16,799 12,171 Other - net ........................................ (20,778) 32,244 --------- --------- Net cash flow provided by operating activities ....... 466,968 476,966 --------- --------- Cash Flows from Investing Activities: Capital expenditures ............................... (221,904) (229,608) Capitalized interest ............................... (12,627) (12,391) Other .............................................. (5,872) (16,798) --------- --------- Net cash flow used for investing activities .......... (240,403) (258,797) --------- --------- Cash Flows from Financing Activities: Long-term debt ..................................... 109,375 109,906 Short-term borrowings - net ........................ (15,400) 100,850 Dividends paid on common stock ..................... (127,500) (127,500) Dividends paid on preferred stock .................. (8,070) (10,334) Repayment of preferred stock ....................... (37,585) (46,511) Repayment and reacquisition of long-term debt ...... (142,250) (222,725) --------- --------- Net cash flow used for financing activities .... (221,430) (196,314) --------- --------- Net increase in cash and cash equivalents ............ 5,135 21,855 Cash and cash equivalents at beginning of period ..... 12,552 12,521 --------- --------- Cash and cash equivalents at end of period ........... $ 17,687 $ 34,376 ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest (excluding capitalized interest) ........ $ 100,929 $ 114,070 Income taxes ..................................... $ 115,585 $ 161,228 See Notes to Condensed Financial Statements. -8- ARIZONA PUBLIC SERVICE COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS 1. In the opinion of the Company, the accompanying unaudited condensed financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly the financial position of the Company as of September 30, 1998, the results of operations for the three months, nine months and twelve months ended September 30, 1998 and 1997, and the cash flows for the nine months ended September 30, 1998 and 1997. It is suggested that these condensed financial statements and notes to condensed financial statements be read in conjunction with the financial statements and notes to financial statements included in the 1997 10-K. Certain prior year balances have been restated to conform to the current year presentation. 2. The Company's operations are subject to seasonal fluctuations, with variations in energy usage by customers occurring from season to season and from month to month within a season, primarily as a result of changing weather conditions. For this and other reasons, the results of operations for interim periods are not necessarily indicative of the results to be expected for the full year. 3. All the outstanding shares of common stock of the Company are owned by Pinnacle West. 4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the nine months ended September 30, 1998. 5. Regulatory Matters ___ Electric Industry Restructuring STATE The following is a description of regulatory and legislative developments related to implementation of retail electric competition beginning with the ACC rules adopted in December 1996 through the proposed settlement agreement in November 1998. ACC RULES. In December 1996, the ACC adopted rules that provide a framework for the introduction of retail electric competition in Arizona. On August 5, 1998, the ACC adopted amendments to the rules. The ACC rules, as amended, include the following major provisions: o The rules apply to virtually all of the Arizona electric utilities regulated by the ACC, including the Company. o The rules require each affected utility, including the Company, to make available at least 20% of its 1995 system retail peak demand for competitive generation supply to all customer classes beginning January 1, 1999, and 100% beginning January 1, 2001. -9- o All affected utility customers with single premise loads of one megawatt or greater will be eligible for competitive electric services beginning January 1, 1999, until the 20% level described in the preceding paragraph is met. Until the 20% level is met, affected utility customers with single premise loads of forty kilowatts or greater will be able to aggregate into a combined load of one megawatt or greater to be eligible for competitive electric services beginning January 1, 1999. o Prior to January 1, 2001, residential customers will have access to competitive services through a quarterly phase-in of one-half percent of residential customers per quarter beginning January 1, 1999. o Electric service providers that obtain Certificates of Convenience and Necessity (CC&Ns) from the ACC will be allowed to supply, market, and/or broker specified electric services at retail. These services include electric generation, but exclude electric transmission and distribution. o As required by the rules, in February 1998 the Company filed with the ACC proposed tariffs for unbundled service (electric service elements provided and priced separately). The ACC has not issued a decision in this matter. o The rules establish that the ACC shall allow a reasonable opportunity for the recovery of unmitigated stranded costs. See "Stranded Costs" below. Affected utilities are expected to take reasonable, cost-effective steps to mitigate stranded costs. o Absent a waiver from the ACC, each affected utility must separate itself from all competitive generation assets and services prior to January 1, 2001. The separation must be either to an unaffiliated party or to a separate corporate affiliate or affiliates. o Beginning January 1, 1999, each affected utility will be prohibited from providing certain competitive electric services, except through a separate affiliate. o The rules contain affiliate transaction rules generally prohibiting an affected utility and its competitive electric affiliates from sharing personnel, office space, equipment, services, and systems, except to the extent appropriate to perform certain permissible shared corporate support functions. No later than December 31, 1998, each affected utility must file a compliance plan with the ACC demonstrating its compliance with the affiliate transaction rules. In accordance with the rules, on September 15, 1998, the Company filed a report detailing possible mechanisms to provide certain non-rate benefits and a possible extension of the 1996 regulatory agreement to all standard offer customers and a proposed plan for phase-in implementation of 3,500 residential customers per quarter -10- on a first come, first served basis. The amended rules became effective on an emergency basis upon their filing with the Secretary of State on August 10, 1998. The ACC held hearings on the amended rules in October 1998 and must complete the process of adopting the amended rules on a permanent basis within 180 days of the Secretary of State filing. The Company anticipates the completion of this process by year-end 1998 or early 1999. The Company believes that certain provisions of the 1996 ACC rules and the amended rules are deficient. In February 1997, a lawsuit was filed by the Company to protect its legal rights regarding the 1996 rules. That lawsuit is pending but two related cases filed by other utilities have been partially decided in a manner adverse to those utilities' positions. In October 1998, the Company also filed a lawsuit to protect its legal rights regarding the amended rules. STRANDED COSTS. In February 1998, the ACC completed a formal, generic hearing on stranded cost determination and recovery. On June 22, 1998, the ACC issued an order in this matter. The order allows an affected utility, such as the Company, to choose between two options for the recovery of its stranded costs. Under the first option, an affected utility that chooses to divest its generating assets must file a divestiture plan for ACC approval no later than October 1, 1998, and such divestiture must be completed by January 1, 2001, after which the affected utility would be permitted to collect 100 percent of its stranded costs, including a return on the unamortized balance, over a ten-year period. Under the second option (referred to by the ACC as the "Transition Revenues Methodology"), an affected utility would be provided sufficient revenues necessary to maintain financial integrity for a period of ten years or the ACC would "otherwise provide an allocation of stranded cost responsibilities and risks between ratepayers and shareholders as is determined to be in the public interest." The order also states an intent that the various recovery options "will provide the affected utilities sufficient revenues to enable them to recover appropriate regulatory assets." In accordance with the order, on August 21, 1998 the Company filed with the ACC the Transition Revenues Methodology as its choice of options for stranded cost recovery and a related implementation plan relating to its chosen option. The Company does not intend to divest its generating assets except to an affiliated party. The Company believes that certain provisions of the stranded cost order are deficient and in August 1998 the Company filed two lawsuits to protect its legal rights relating to the order. Based on various assumptions, estimates and methodologies, the Company estimates its recoverable stranded costs (excluding regulatory assets which have already been addressed in the 1996 regulatory agreement with the ACC) to be $533 million, assuming a measurement period 1999 through 2004. The Company cannot accurately predict the outcome of this matter. PROPOSED SETTLEMENT AGREEMENT. On November 4, 1998, the Company and the ACC Staff entered into a proposed settlement agreement related to the implementation of retail electric competition. In connection with the settlement agreement, the Company and TEP entered into a memorandum of understanding for the exchange of certain -11- assets. The following are the major provisions of each agreement, both of which are attached as exhibits to this Form 10-Q and incorporated herein by reference: PROPOSED SETTLEMENT AGREEMENT WITH ACC STAFF o The Company will reduce its prices by a total of at least 4% in the years 1999 through 2002. Price reductions in 2001 and 2002 will apply only to the Company's residential customers who purchase all their electric services from the Company. o There will be a moratorium on filing for retail rate changes before January 1, 2003, except for the price reductions described above and certain other limited circumstances. o In addition to the cost-saving incentive mechanism, the rate filing moratorium and full recovery of regulatory assets, certain other aspects of the 1996 regulatory settlement are extended through 2002. See Note 6 below for additional information on the 1996 regulatory agreement. o The Company will be permitted to defer for later recovery prudent and reasonable costs of complying with the amended ACC rules, systems benefits costs and solar power costs in excess of the levels included in current rates. o The Company will have the ability to recover stranded costs in exchange for the divestiture of its 345 kV and 500 kV transmission assets to TEP. o The Company and TEP entered into a memorandum of understanding for the exchange of certain assets. o Upon final adoption and approval of the settlement agreement by the ACC, the Company will move to dismiss all of its litigation currently pending against the ACC. o The Company will establish a separate corporate affiliate for marketing generation and other competitive electric services before year-end 1998. o The Company will form a separate corporate affiliate and transfer to it generating assets by year-end 2002. MEMORANDUM OF UNDERSTANDING WITH TEP o The Company and TEP have entered into a memorandum of understanding to negotiate in good faith to reach a definitive agreement on the exchange of certain transmission and generation assets. o The Company would acquire from TEP up to 273 MW of generating capacity in exchange for the Company's 500 kV and 345 kV transmission lines. The assets -12- will be exchanged at the transmission current book value, which is approximately $162 million as of July, 1998. If TEP is unable to transfer 273 MW of generating capacity, the deficiency is to be made up by a cash payment from TEP to the Company. o The transaction is expected to close by December 31, 2000. o The generating assets are TEP's interest in the Navajo Generating Station and Four Corners Generating Plant. A hearing date for the ACC's consideration or approval of the settlement agreement has not yet been set. The memorandum of understanding provides that a definitive agreement must be entered into within sixty days of a final order on the settlement agreement by the ACC. LEGISLATIVE INITIATIVES. An Arizona joint legislative committee studied electric utility industry restructuring issues in 1996 and 1997. In conjunction with that study, 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 (the ability of the ACC to set rates based on the competitive market) has been subsequently decided by lower courts in favor of the ACC in two unrelated and two related lawsuits. In May 1998, a bill was enacted to facilitate implementation of retail electric competition in the state. The bill includes the following major provisions: (a) requirements that Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller city electric systems (i) open their service territories to electric service providers to implement retail electric generation competition for 20% of each utility's 1995 retail peak demand 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, including judicial review at the request of either an interested party or the Arizona Attorney General, for establishing the terms, conditions and pricing of electric services as well as certain other decisions affecting retail electric competition, which procedures and processes are comparable to those already applicable to public service corporations; (b) a description of the factors which form the basis of consideration by Salt River Project in determining stranded costs; and (c) a requirement that metering and meter reading services 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 legislature on certain competitive issues. -13- FEDERAL The Energy Policy Act of 1992 and recent rulemakings by FERC have promoted increased competition in the wholesale electric power markets. The Company does not expect these rules to have a material impact on its financial statements. Several electric utility reform bills have been introduced during recent congressional sessions, which as currently written, would allow consumers to choose their electricity suppliers by 2000 or 2003. 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. REGULATORY ACCOUNTING The Company prepares its financial statements in accordance with the provisions of 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. The Company's existing regulatory orders and current regulatory environment support its accounting practices related to regulatory assets, which amounted to approximately $0.9 billion at September 30, 1998. In accordance with the 1996 regulatory agreement, the ACC accelerated the amortization of substantially all of the Company's regulatory assets to an eight-year period that began July 1, 1996. During 1997, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) issued 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. Although the ACC has issued rules for transitioning generation services to competition, there are many unresolved issues. The Company continues to apply SFAS No. 71 to all of its operations. If rate recovery of regulatory assets is no longer probable, whether due to competition or regulatory action, the Company would be required to write off the remaining balance as an extraordinary charge to expense. -14- GENERAL Changes in ACC decisions, Arizona and federal legislation, and possible amendments to the Arizona Constitution may impact the implementation of retail electric competition in Arizona. Until the details of implementation of competition, including addressing stranded costs, are determined, the Company cannot accurately predict the impact of full retail competition on its financial position, cash flows or results of operation. As competition in the electric industry continues to evolve, the Company will continue to evaluate strategies and alternatives that will position the Company to compete in the new regulatory environment. 6. Regulatory Matters ___ 1996 Regulatory Agreement In April 1996, the ACC approved a regulatory agreement between the Company and the ACC Staff. The major provisions of this agreement are: o 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. o Recovery of substantially all of the Company's present regulatory assets through accelerated amortization over an eight-year period that began July 1, 1996, increasing annual amortization by approximately $120 million ($72 million after income taxes). o A formula for sharing future cost savings between customers and shareholders (price reduction formula) referencing a return on equity (as defined) of 11.25%. o 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. o Infusion of $200 million of common equity into the Company by Pinnacle West, in annual payments of $50 million starting in 1996. Pursuant to the price reduction formula, in 1997 and in 1998, 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, respectively. 7. Agreement with Salt River Project On April 25, 1998, the Company and Salt River Project entered into a Memorandum of Agreement in anticipation of, and to facilitate, the opening of the Arizona electric industry. The Agreement contains the following major components: -15- o The Company and Salt River Project would amend the Territorial Agreement to remove any barriers to the provision of competitive electricity supply and non-distribution services. o The Company and Salt River Project would amend the Power Coordination Agreement to lower the price that the Company will pay Salt River Project for purchased power by approximately $17 million (pretax) in 1999 and by lesser annual amounts through 2006. o The Company and Salt River Project agreed on certain legislative positions regarding electric utility restructuring at the state and federal level. An ACC docket had previously been established and the ACC held a hearing on August 6, 1998 so that the ACC could review certain provisions of the Memorandum of Agreement, as amended, including, whether: (a) the Territorial Agreement remains in the public interest, (b) the Agreement is a contract in restraint of trade, and (c) the Agreement will materially lessen the potential for retail electric competition in Arizona. The Antitrust Unit of the Arizona Attorney General's Office, which has been involved in the ongoing regulatory and legislative proceedings regarding the restructuring of the Arizona electric industry, requested clarification of the operation of certain of the Agreement's provisions. Pursuant to an Addendum to Memorandum of Agreement, dated as of May 19, 1998 (the "Addendum"), the Company and Salt River Project amended and clarified certain provisions of the Memorandum of Agreement in response to certain issues raised by the Antitrust Unit. By letter dated May 19, 1998, the Antitrust Unit advised the Company and Salt River Project that, upon their execution of the Addendum, it would take no action regarding the language of the Memorandum of Agreement, although it reserved the right to take action in the future if new information justified doing so. 8. 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, the Company 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 the Company's 29.1% interest in the three Palo Verde units, the Company's 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 -16- stabilization and decontamination. The Company 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. 9. The Financial Accounting Standards Board issued SFAS No. 131 on "Disclosures about Segments of an Enterprise and Related Information" which is effective for fiscal years beginning after December 15, 1997. SFAS No. 131 requires that public companies report certain information about operating segments in their financial statements. It also establishes related disclosures about products and services, geographic areas, and major customers. The Company is currently evaluating what impact this standard will have on its disclosures. In June 1998 the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," which is effective for the Company in 2000. SFAS No. 133 requires that an entity recognize all derivatives as either assets or liabilities in 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 Company is currently evaluating what impact this standard will have on its financial statements. -17- ARIZONA PUBLIC SERVICE COMPANY Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. OPERATING RESULTS The following table summarizes the Company's revenues and earnings for the three-month, nine-month and twelve-month periods ended September 30, 1998 and 1997:
Periods ended September 30 (Unaudited) (Thousands of Dollars) Three Months Nine Months Twelve Months ----------------------- ----------------------- ----------------------- 1998 1997 1998 1997 1998 1997 ---------- ---------- ---------- ---------- ---------- ---------- Operating Revenues $ 740,734 $ 632,821 $1,562,872 $1,470,593 $1,970,832 $1,850,047 Earnings for Common Stock $ 130,846 $ 126,715 $ 209,652 $ 218,032 $ 230,310 $ 212,837
OPERATING RESULTS - THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1998 COMPARED WITH THREE-MONTH PERIOD ENDED SEPTEMBER 30, 1997 Earnings increased $4 million in the three-month comparison primarily because of customer growth, weather effects, and higher profitability from power marketing activities, partially offset by higher fuel expenses and a retail price reduction. See Note 6 of Notes to Condensed Financial Statements for information on the price reduction. Operating revenues increased $108 million because of increased power marketing revenues ($71 million), customer growth ($28 million), and weather effects ($18 million), partially offset by the price reduction ($6 million) and other ($3 million). The increase in power marketing revenues was a result of higher market prices and increased activity. The increase in power marketing revenues was accompanied by related increases in purchased power. Fuel expenses increased $94 million primarily because of higher purchased power prices, increased wholesale and retail sales volumes, and the effects of two fuel-related settlements in the third quarter of 1997. The settlements contributed approximately $21 million to 1997 pretax earnings and are reflected on the income statement as reductions in fuel expense and as other income. -18- OPERATING RESULTS - NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1998 COMPARED WITH NINE-MONTH PERIOD ENDED SEPTEMBER 30, 1997 Earnings decreased $8 million in the nine-month comparison primarily because of two fuel-related settlements recorded in 1997, increased operations and maintenance expenses, the effects of weather, and two retail price reductions, partially offset by customer growth and higher profitability from power marketing activities. See Note 6 of Notes to Condensed Financial Statements for additional information about the price reduction. The two fuel-related settlements increased the Company's 1997 pretax earnings by approximately $21 million. The Company's income statement reflects these settlements as reductions in fuel expense and as other income. Operations and maintenance expenses increased $22 million related to impending competition and growth, outages at power plants and other miscellaneous factors. Operating revenues increased $92 million because of increased power marketing revenues ($69 million) and customer growth ($58 million). These factors were partially offset by the effects of weather ($20 million) and the price reductions ($15 million). The increase in power marketing revenues was a result of higher prices and increased activity. The increase in power marketing revenues was accompanied by related increases in purchased power. OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1998 COMPARED WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 1997 Earnings increased $17 million in the twelve-month comparison primarily because of customer growth and higher profitability from power marketing activities. These positive factors more than offset two retail price reductions and the effects of weather. See Note 6 of Notes to Condensed Financial Statements for additional information about the price reductions. The period ended September 30, 1997 also benefited from two fuel-related settlements and the recognition of $8 million of income tax benefits associated with capital loss carryforwards. Operating revenues increased $121 million because of increased power marketing revenues ($85 million) and customer growth ($69 million), partially offset by the price reductions ($18 million), the effects of weather ($10 million), and other ($5 million). The increase in power marketing revenues was a result of higher prices and increased activity. The increase in power marketing revenues was accompanied by related increases in purchased power. -19- The two fuel-related settlements increased the Company's 1997 pretax earnings by approximately $21 million. The Company's income statement reflects these settlements as reductions in fuel expense and as other income. Operations and maintenance expenses decreased $8 million because of a $32 million pretax charge for a voluntary severance program recorded in 1996 and related savings in 1997, partially offset by higher expenses related to impending competition and growth, outages at power plants and other miscellaneous factors. OTHER INCOME As part of a 1994 rate settlement with the ACC, the Company accelerated amortization of substantially all deferred ITCs over a five-year period that ends on December 31, 1999. The amortization of ITCs is shown on the Company's income statement as Other Income ___ Income Taxes and decreases annual income tax expense by approximately $28 million. LIQUIDITY AND CAPITAL RESOURCES For the nine months ended September 30, 1998, the Company incurred approximately $221 million in capital expenditures, which is approximately 68% of the most recently estimated 1998 capital expenditures. The Company's projected capital expenditures for the next three years are: 1998, $323 million; 1999, $322 million; and 2000, $317 million, respectively. These amounts include about $30 - $35 million each year for nuclear fuel expenditures. In addition, the Company is considering expanding certain of its businesses over the next several years, which may result in increased expenditures. The Company's long-term debt and preferred stock redemption requirements and payment obligations on a capitalized lease for the next three years are: 1998, $221 million; 1999, $174 million; and 2000, $104 million. During the nine months ended September 30, 1998, the Company redeemed approximately $142 million of its long-term debt and approximately $38 million of its preferred stock with cash from operations and long-term and short-term debt. On December 1, 1998 the Company will redeem all $37.5 million of its $1.8125 Cumulative Preferred Stock, Series W. As a result of the 1996 regulatory agreement (see Note 6 of Notes to Condensed Financial Statements), Pinnacle West invested $50 million in the Company in 1996 and 1997 and will invest similar amounts annually in 1998 and 1999. Although provisions in the Company's bond indenture, articles of incorporation, and financing orders from the ACC establish maximum amounts of additional first mortgage bonds and preferred stock that the Company may issue, management does -20- not expect any of these restrictions to limit the Company's ability to meet its capital requirements. YEAR 2000 READINESS DISCLOSURE As the year 2000 approaches many companies face problems because most software application and operational programs will not properly recognize calendar dates beginning with the year 2000. The Company initiated a comprehensive Company-wide Year 2000 program over a year ago to review and resolve all Year 2000 issues in critical systems and equipment in a timely manner to avoid impacting the reliability of electric service to its customers. This included a Company-wide awareness program of the Year 2000 issue. The Company has been actively implementing and replacing new systems and technology since 1995 for reasons unrelated to the year 2000, and these actions have resulted in substantially all of its major information technology (IT) systems becoming Year 2000 compliant. The Company has made, and will continue to make, certain modifications to its computer hardware and software systems and applications to ensure they are capable of handling changing business needs, including dates in the year 2000 and thereafter. In addition, other IT systems and non-IT systems, including embedded technology and real-time process control systems, are being analyzed for potential modifications. To date, the Company has inventoried and assessed all IT and non-IT systems and any renovation, validation and implementation of these systems will be completed by mid-1999, except for those items that can only be completed during maintenance outages at Palo Verde, which will be completed for the last unit during the last half of 1999. The Company has also designated an internal audit/quality review team that is periodically reviewing the individual Year 2000 projects and their Year 2000 readiness. The Company is communicating with its significant suppliers, business partners, other utilities and large customers to determine the extent to which it may be affected by these third parties' plans to remediate their own Year 2000 issues in a timely manner. The Company has 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. The Company is also working with the North American Electric Reliability Council (NERC) through the Western Systems Coordinating Council (WSCC) to develop operational plans for stable grid operation that will be utilized by the Company and other utilities in the western United States. However, the Company cannot currently predict the effect on the Company if the systems of these other companies are not Year 2000 compliant. The Company currently estimates that it will spend approximately $5 million relating to Year 2000 issues, about half of which has been spent to date. This does not include expenditures incurred since 1995 to implement and replace systems for -21- reasons unrelated to the Year 2000, as discussed above. Costs incurred to address the Year 2000 issue are charged to operating expenses as incurred and are expected to be funded by available cash balances and cash provided by operations. The Company currently expects that its most reasonably likely worst case Year 2000 scenario would be intermittent loss of power, similar to an outage during a severe weather disturbance. In this situation the Company would restore power as soon as possible by, among other things, re-routing power flows. The Company does not currently expect that this scenario would have a material effect on its financial position, cash flows or results of operations. The Company is working to develop its own contingency plans to handle Year 2000 issues, and expects these plans to be completed by mid-1999. As discussed above, the Company is also working with NERC and WSCC to develop contingency plans related to grid operation. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for discussions of competitive developments and regulatory accounting. See Note 7 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of a proposed amendment to a Power Coordination Agreement with Salt River Project that the Company estimates would reduce its pretax costs for purchased power by approximately $17 million in 1999 and by lesser annual amounts through 2006. RATE MATTERS See Note 6 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of a price reduction, which became effective on July 1, 1998. 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 the Company 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; and Year 2000 issues. -22- These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by the Company. -23- 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 the Company's construction and financing programs. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See Note 5 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of competition and the rules regarding the introduction of retail electric competition in Arizona. On February 28, 1997 and October 16, 1998, lawsuits were filed by the Company to protect its legal rights regarding the rules and the amended rules, respectively, and in each complaint the Company asked the Court for (i) a judgment vacating the retail electric competition rules, (ii) a declaratory judgment that the rules are unlawful because, among other things, they were entered into without proper legal authorization, and (iii) a permanent injunction barring the ACC from enforcing or implementing the rules and from promulgating any other regulations without lawful authority. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 97-03753 (consolidated under CV 97-03748.) ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-18896. On August 28, 1998, the Company filed two lawsuits to protect its legal rights under the stranded cost order and in its complaints the Company asked the Court to vacate and set aside the order. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, CV 98-15728. ARIZONA PUBLIC SERVICE COMPANY v. ARIZONA CORPORATION COMMISSION, 1-CA-CC-98-0008. See "State-Proposed Settlement Agreement" in Note 5 of Notes to Condensed Financial Statements in this Report regarding the possible dismissal of the lawsuits described in this paragraph. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits EXHIBIT NO. DESCRIPTION - ----------- ----------- 27.1 Financial Data Schedule 99.1 Settlement Agreement with the ACC dated November 4, 1998, which includes a Memorandum of Understanding with TEP 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: -24-
EXHIBIT NO. DESCRIPTION ORIGINALLY FILED AS EXHIBIT: FILE NO.(a) DATE EFFECTIVE - ----------- ----------- ---------------------------- --------- -------------- 3.1 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 3-29-96 February 20, 1996 Report 3.2 Resolution of Board of 3.2 to 1994 Form 10-K 1-4473 3-30-95 Directors temporarily Report suspending Bylaws in part 3.3 Articles of Incorporation, 4.2 to Form S-3 1-4473 9-29-93 restated as of May 25, 1988 Registration Nos. 33-33910 and 33-55248 by means of September 24, 1993 Form 8-K Report 3.4 Certificates pursuant to 4.3 to Form S-3 1-4473 9-29-93 Sections 10-152.01 and Registration Nos. 10-016, Arizona Revised 33-33910 and 33-55248 by Statutes, establishing Series A means of September 24, through V of the Company's 1993 Form 8-K Report Serial Preferred Stock 3.5 Certificate pursuant to 4.4 to Form S-3 1-4473 9-29-93 Section 10-016, Arizona Registration Nos. Revised Statutes, establishing 33-33910 and 33-55248 by Series W of the Company's means of September 24, Serial Preferred Stock 1993 Form 8-K Report
(b) Reports on Form 8-K During the quarter ended September 30, 1998, and the period from October 1 through November 13, 1998, the Company filed the following reports on Form 8-K: Report dated August 5, 1998 regarding the ACC rules related to retail competition. - -------- (a) Reports filed under File No. 1-4473 were filed in the office of the Securities and Exchange Commission located in Washington, D.C. -25- SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated: November 13, 1998 By: George A. Schreiber, Jr. -------------------------------------- George A. Schreiber, Jr. Executive Vice President and Chief Financial Officer (Principal Financial Officer and Officer Duly Authorized to sign this Report) EX-27.1 2 FINANCIAL DATA SCHEDULE UT
UT 1000 U.S. DOLLARS 9-MOS DEC-31-1998 JAN-01-1998 SEP-30-1998 1 PER-BOOK 4,687,675 186,342 514,007 1,064,409 0 6,452,433 178,162 1,143,617 610,535 1,932,314 9,401 123,795 1,871,949 0 0 115,350 154,220 0 0 0 2,245,404 6,452,433 1,562,872 162,808 1,100,145 1,262,953 299,919 19,179 319,098 101,786 217,312 7,660 209,652 127,500 87,558 466,968 0 0
EX-99.1 3 SETTLEMENT AGREEMENT ARIZONA PUBLIC SERVICE COMPANY, INC. DOCKET NO. E-01345A-98-0473 DOCKET NO. E-01345A-97-773 DOCKET NO. RE-00000C-94-0165 SETTLEMENT AGREEMENT -------------------- The undersigned parties stipulate and agree to the following settlement provisions in connection with the following applications submitted to the Arizona Corporation Commission ("Commission") by Arizona Public Service Company, Inc. ("APS" or "Company"): Docket No. E-01345A-98-0473 and Docket No. E-01345-97-773. In addition, this Settlement Agreement ("Agreement") settles all issues arising from or related to the Commission's Electric Competition Rules as set forth in Decision Nos. 59943, 60977 and 61071. STATEMENT OF INTENTION. The purpose of this Agreement is to resolve contested matters in a manner consistent with the public interest. The contested matters were generated, in large measure, as a result of the Commission's Retail Electric Competition Rules and APS' regulatory filings made in response thereto. The parties recognize that the electric utility industry is undergoing a transition to competition, which is scheduled to begin on January 1, 1999. It is the intention of the parties, APS and Commission Staff ("Staff"), through this Agreement, to provide resolution of the contested matters regarding APS' unbundled tariffs, APS' requested stranded cost recovery, and certain outstanding matters related to the Commission's Retail Electric Competition Rules. This settlement is intended to be comprehensive, fair to APS, its shareholders and customers and will serve to make an efficient and cost effective transition to a new era of customer choice in a competitive market structure. Therefore, the parties believe that this settlement is in the public interest. The parties also agree that in exchange for APS divesting its Transmission Assets, as defined below, APS shall fully recover its stranded costs, as described herein. Under this Agreement, the basis for APS' opportunity to recover its stranded cost is the divestiture of APS' Transmission Assets including 345 kV and above. The failure of APS to divest of its Transmission Assets as provided herein will eliminate APS' opportunity to recover its stranded costs in the manner provided by this Agreement. Instead, the Commission may award transition revenues to APS in order to maintain its financial viability. For purposes of this Agreement, the term "divestiture" under the Commission's rules includes APS' divestiture of Transmission Assets as agreed to herein. Staff believes that APS' divestiture of these Transmission Assets limits the potential for APS to exercise vertical market power and as such constitutes a change in market structure in the transition to competition. I. CONTINGENCY OF AGREEMENT. This Agreement is contingent upon Commission approval of the Agreement in its entirety and without modification pursuant to a final and non-appealable order. II. UNBUNDLED RATES. The Company's unbundled rates and charges will reflect (1) the embedded cost of service for all functions as approved by the Commission, (2) the 1.1 percent rate reduction approved by the Commission in Decision No. 61103 (August 28, 1998) and (3) separately identify distribution, transmission, metering, billing and system benefits and the remaining generation service, which shall consist of a Competition Transition Charge, ("CTC") a nonbypassable charge for Regulatory Assets, and a Market Generation Credit ("MGC"). Current recovery levels of Regulatory Assets will continue until all Regulatory Assets are recovered, at which point APS will, without further Commission action, adjust its prices to remove any charges for Regulatory Asset recovery, unless APS demonstrates and the Commission finds that APS has experienced offsetting increased revenue requirements attributable to Commission-regulated APS electric services. The quarterly Market Generation CreditS (MGC) shall be calculated for peak and off-peak hours for the next twelve months based on the Palo Verde Nymex futures price, plus 3 mills, and brought to the retail delivery level by multiplying by 1 plus the appropriate line loss. The peak and off peak prices shall be determined by shaping the Palo Verde Nymex futures price by actual hourly prices from the California spot price index. The adder will be adjusted for each class for differences between the class load factor and the system average load factor before being included in the MGC. The basic 3 mill adder shall remain in effect unchanged unless 25% of the load eligible for competition has not selected an alternative supplier by December 31, 2000, in which case the adder will be increased to 3.5 mills. By September 1, 2002, Staff and APS shall present to the Commission their recommendations regarding the appropriate Market Generation Credit for the period from January 1, 2003 until the CTC collection ends. At this same time, Staff and APS shall also present recommendations regarding the longer-term provision of Provider of Last Resort service. The monthly competitive transition charges shall be the residual after subtracting distribution, transmission, metering, billing, system benefits, the regulatory asset charge and the retail MGCs from the bundled tariff. The computation of the MGC and the CTC charge will be described in Exhibit A to this Agreement. In addition, APS may file by September 1, 1999 an overall Company "revenue neutral" rate case to realign standard offer and unbundled rates in accordance with appropriate cost allocation and rate design principles. The Commission shall take such action as is necessary to rule on the Company's filing that redesigned, overall Company revenue neutral, rates will be effective as of January 1, 2001. This rate application will not change the Company's currently authorized cost of capital or request an overall revenue increase. There may be a mismatch between the projected MGC and the MGC that would have resulted from the forward price at the close of each month for the following month. The 2 difference between these two forward prices for the same month multiplied by the competitive sales in a month shall be interpreted as an over or undercollection of stranded costs. Monthly under and overcollections shall be accumulated with a reasonable carrying charge. If the accumulated undercollection reaches $5 million, the Company may increase the generation component of all rates by a factor that would collect these dollars within one year.. At the end of the fixed rate period (end of 2002) or upon the cessation of the regulatory asset charge, if this occurs earlier, the Company shall increase or decrease generation rate charges to collect or return this amount during the remaining CTC period. III. RECOVERY OF REGULATORY ASSETS. APS will be allowed 100 percent recovery of regulatory assets in accordance with Section II. These will be identified separately in the unbundled tariffs. IV. TRANSITION REVENUES/STRANDED COSTS APS and Tucson Electric Power Company ("TEP") have executed the memorandum of understanding ("MOU"), attached hereto as Exhibit B, for the exchange of certain APS transmission assets, consisting of its 345 kV and 500kV facilities ("Transmission Assets"), for TEP's interests in the Four Corners Generating Plant and Navajo Generating Plant. The MOU commits both parties to negotiate in good faith to reach a definitive agreement on the exchange of assets. This MOU also outlines the structure of the transaction, describes the assets to be included in the exchange, establishes the Parties' good faith estimate of asset values, establishes a transmission pricing structure and lists the conditions to closing the transaction. These closing conditions include (1) securing independent appraisals and fairness opinions, and (2) obtaining all necessary consents and approvals from regulatory agencies and third parties in a form and substance satisfactory to both parties. This MOU is supported in its entirety by Commission Staff and approval of this Settlement Agreement by the Commission shall be deemed to constitute all requisite approvals necessary to consummate the transaction described in the MOU. In the event that APS divests its transmission assets according to the MOU, APS will be allowed recovery of transition revenues through a CTC according to Section II of this Agreement until December 31, 2004. As part of this Agreement, the Commission will not alter the transition revenue amounts before December 31, 2004 unless the Commission finds that APS or its competitive affiliate has significant market power and has manipulated the market price for power in the region. This exceptions will allow the Commission to adjust, terminate or declare interim and subject to refund the transition revenue amount reflected in the CTC. In the event that APS does not divest its transmission assets according to the MOU, except to the extent that any joint owner of any such assets exercises a right of first refusal, APS will not be allowed recovery of stranded costs through a CTC but rather interim transition 3 revenues will be implemented as identified in this Agreement. APS may file an application with the Commission to recover transition revenues based on its financial viability and actual load lost to unaffiliated electric service providers. It is anticipated that divestiture would occur in a transaction closing no later than December 31, 2000. V. DIVESTITURE. Staff believes that achieving the following three objectives will limit the ability of APS to exercise vertical market power and will assist in achieving competition: (1) all network customers in an access area (or zone) should pay the same rate for transmission service. (2) all customers should have access to any generation within the region at no additional cost; and (3) transmission constraints and/or the allocation of Available Transmission Capacity ("ATC") should not be allowed to unduly frustrate competition. These objectives can be met using either a region-wide "postage stamp" approach or a properly implemented "license plate" approach. If a "license plate" approach is to be used, it needs to be "all inclusive", i.e., all intra-regional transmission costs currently being paid by network customers within each access area need to be absorbed by the access area provider and reflected in the "license plate" rate. Under any pricing approach, congestion management and ATC determination will be crucial to a successful implementation. The following principles will apply : <- Subject to rights of first refusal which may be exercised by joint owners, APS shall transfer to TEP's affiliate ("Transco") all transmission facilities owned by APS at a voltage level of 345 kV and above. This is required for all components of the transmission system that may be subject to Committed Uses or constraints which, in turn, may be used to promote Vertical Market Power. <- APS shall file an application with FERC to place all facilities below the voltage level of 345 kV (which APS asserts serve a distribution function) under the jurisdiction of the ACC, with appropriate provisions for wholesale customers subject to FERC's jurisdiction. <- APS will work with the Transco to file comparable network and point-to-point tariffs, providing transmission service on a "license plate" basis over the combined APS/TEP service areas, and including adjacent systems as appropriate when the Independent Scheduling Administrator ("ISA") and/or Independent System Operator ("ISO") is implemented. <- APS will work with TEP to pursue the "license plate" approach and requisite filings even if the current ISA implementation plan fails to materialize or receive FERC approval as currently proposed. <- APS will work with TEP to ensure that all Committed Uses under their control will be used for all customers within their respective access areas on a non-discriminatory basis: 4 <- APS will provide Staff with a comprehensive definition and explanation of all Committed Uses supported by APS (existing or contemplated). > If FERC rejects or otherwise orders APS to modify its commitments, APS will comply accordingly and will not seek to relieve itself of the obligations accepted herein. > APS will work with TEP to ensure that any and all Committed Uses are applied in a consistent manner for all transmission facilities so that no generation resources are given a competitive advantage by virtue of contractual constraints or protocols (as contemplated in the ISA filing) designed to limit ATC. > APS will pursue in good faith any mitigation measures (Re: The "license plate" approach) that are necessary for a full region-wide Desert Star (or other ISO) implementation without "pancaked" rates. <- APS shall on a regular basis, but not less than quarterly, provide Staff a written report and briefing on the activities described in this section. APS' failure to comply with the provisions of this section, other than the transfer of APS' transmission facilities as described herein, shall not, by itself, provide a basis for the Commission to modify any provision of this Agreement or of the order approving this Agreement, dealing with cost recovery. VI. FERC TRANSMISSION ISSUES APS and TEP will develop and present to FERC a transmission pricing structure for the use of such assets that will not increase rates to customers in APS or TEP's current service territories. APS will enter into a Service Agreement with TEP relating to APS' use of the Transmission Assets under an Open Access Transmission Tariff ("OATT") accepted by FERC. The OATT shall have zonal rates developed for the use of the transmission facilities pursuant to which the transmission rates for any transmission user in either APS' or TEP's current service territory, including APS' merchant group, shall not be adversely affected by the transfer of the Transmission Assets. Where APS transmission users are receiving service under a single agreement for both the Transmission Assets and the lower voltage transmission assets to be retained by APS, the Parties will agree to bifurcate those obligations in a manner that will not result in any cost shifting or increase in transmission costs to such users or APS. The Commission shall support the APS and TEP FERC filings to effectuate the transmission pricing principles described in this paragraph. VII. RATE REDUCTIONS. The existing Second Restated and Amended Rate Reduction Agreement, ("1996 Agreement"), as reflected in Decision No. 59601, will be extended until December 31, 2002, subject to the following revisions. In addition to the revisions listed below, the provisions of the 1996 Agreement that are or will be moot, extended with modifications or extended without 5 modifications, are identified in Exhibit C hereto. Rate reductions for the years 1999 through 2002 will be: For usage on and after July 1, 1999, 1.0% or the APS formula contained in the existing Second Restated and Amended Rate Reduction Agreement, as reflected in Decision No. 59601, using 1998 calendar year, whichever is greater, to be applied to both Standard Offer and unbundled rates; For usage on and after July 1, 2000, 1.0% or the APS formula using 1999 calendar year, whichever is greater, to be applied to both Standard Offer and unbundled rates; For usage on and after July 1, 2001, 1.0% or the APS formula using 2000 calendar year, whichever is greater, to be applied to Standard Offer rates for residential customers only; For usage on and after July 1, 2002, 1.0% or the APS formula using 2001 calendar year, whichever is greater, to be applied to Standard Offer rates for residential customers only. The impact of each year's rate reduction should be implemented through reductions to generation rates that result in equal percentage reductions to each class (including competitive customers). Costs of complying with the Electric Competition Rules, system benefits costs, and solar power costs in excess of levels included in current rates, may be deferred subject to the limitations set forth below. Notwithstanding the rate reduction provisions stated above, the Company's share of any property tax expense decreases shall be used to offset other expense deferrals referred to in this section. In any year that the APS formula is used to calculate the rate reductions, ratepayer's 55% share above the stated, minimum 1% rate reduction, would first be used to reduce amounts otherwise deferrable. APS will be allowed full recovery of any remaining deferrable costs beginning January 1, 2003. APS agrees to make an annual reporting of its level of deferred expenses to be included in its rate reduction filings. APS agrees to meet the requirements of the Solar Portfolio Standard, Section 1609 of the rules, as amended in August 1998. APS agrees to support the continuation of the Solar Portfolio Standard in future Commission proceedings. APS agrees to continue the programs included in the System Benefits Charge at a level equal to or greater than the level at which APS was funding those programs in 1997. As applied to APS (as a utility distribution company), the solar portfolio standard ("SPS") established by the Commission for distribution companies in A.A.C. R14-2-1609(C), as amended in August, 1998, will be met by APS purchasing all the necessary solar power through an RFP process and recovering the associated costs through a "green" solar rate to market such solar power to its Standard Offer customers at a price designed to recover such costs (but, in the event revenue from such rate plus any additional revenue received from the sale of solar power to any other entities is not sufficient to fully recover such costs, any deficiency shall be deferred for recovery [including a reasonable return] as discussed above. The RFP process and cost recovery mechanism will be subject to (1) approval of the RFP by the Director of the Utilities Division by July 1, 1999, and (2) joint approval by APS and the Director of the Utilities Division of a successful, qualified responsive bid to such RFP. 6 VIII. SEPARATION OF MONOPOLY AND COMPETITIVE SERVICES APS will transfer its generation services and competition assets at book value into a separate corporate affiliate no later than December 31, 2002. APS is also granted a waiver from compliance with the provisions of A.A.C. R14-2-1606(B) until December 31, 2002. Approval of this Agreement by the Commission shall be deemed to constitute all requisite Commission approvals for (1) the creation of a new corporate affiliate and the transfer thereto of APS' generation services and competitive assets at book value; and (2) the full and timely recovery through the mechanism referred to in Section VII above for the reasonable and prudent costs of such action. Such transfers may require various regulatory and third party approvals, consents or waivers from entities not subject to APS' control, including the FERC and the NRC. No party to this Settlement Agreement nor the Commission will oppose, or support opposition to, APS requests to obtain such approvals, consents or waivers. By December 15, 1998, the Company will provide the ACC Staff with a detailed description of the process and the time necessary for a transfer of its generation and competitive service assets into a separate corporate affiliate. The Company shall also specify the nature and magnitude of any associated transaction costs that APS will request be recovered in rates. By November 15, 1998, the Company will establish a separate energy services corporate affiliate (approval of which shall be deemed given by Commission approval of this Agreement) and will apply for a competitive CC&N to provide such competitive retail generation and other competitive services as it intends to offer. No later than November 30, 1998, the Company will file in the competitive CC&N docket a code of conduct that will address any and all concerns regarding the separation of monopoly and competitive services that arise from forming and operating a competitive affiliate while retaining generation assets until December 31, 2002. Staff will recommend to the Commission, by December 1, 1998, that it grant such application, subject only to such conditions as are reasonably imposed on other Energy Service Providers, unless specific circumstances warrant additional conditions. IX. INDEPENDENT SCHEDULING ADMINISTRATOR/INDEPENDENT SYSTEM OPERATOR. The Company shall commit to having an independent scheduling administrator ("ISA") in place and operational by April 1, 1999, and commit to facilitating the development of an independent system operator ("ISO") for Arizona by December 31, 2000. APS shall , on a regular basis, but not less than quarterly, provide Staff a written report and briefing on the status of the ISA and ISO. In the event APS does not have an independent scheduling administrator in place by December 31, 1998 or, an independent system operator by December 31, 2002, the Commission shall examine the reason(s) for the failure and the efforts expended by APS in compliance with this Section. APS' failure to comply with the provisions of this section shall not, by itself, provide a basis for the Commission to modify any provision of this Agreement or of the order approving this Agreement, dealing with cost recovery The ISA/ISO also calculates available transmission capacity and implements protocols for system transfer capabilities, committed uses of the transmission system, must-run generating units (as 7 determined by the Commission) and provides dispute resolution such that market participants can expeditiously resolve dispute claims. If an Arizona only ISO is established, it is anticipated that it would join a regional ISO when one is established. XI. SECTION 40-252 - CERTIFICATE OF CONVENIENCE AND NECESSITY APS agrees to modify its Certificate(s) of Convenience and Necessity to permit competition pursuant to A.A.C. R14-2-1600, et seq., as amended in August 1998. The order adopting this Settlement Agreement shall constitute the necessary Commission Order modifying APS' CC&Ns to permit competition. XII. RESOLUTION OF LITIGATION. Upon issuance by the Commission of a final, non-appealable order approving this Agreement, APS shall move to dismiss with prejudice all pending litigation brought by APS against the Commission. As mutually agreed, APS will actively support the Commission's position and assist the Commission in any remaining litigation regarding the Commission's Electric Competition Rules or related matters. XIII. MUST RUN ASSETS. To the extent such contracts are not subject to FERC jurisdiction, contracts regarding the sale of output from must run generation units shall be reviewed and approved by the Commission. XIV. WAIVERS. APS has requested waiver of certain Affiliated Interest Rules. Staff concurs with APS' requests for waivers of certain Affiliated Interest Rules, and agrees that the Commission's approval of this Agreement will constitute the Commission's granting of the waivers, under the following conditions and limitations:- R14-2-801(5) APS has requested a waiver of the definition of "reorganization" to exclude corporate reorganizations that do not involve a reconfiguration of the utility distribution company ("UDC") in the holding company structure. Under the waiver proposed by APS, the holding company would be free to reorganize, buy or sell non-regulated affiliates without Commission approval. Staff agrees that R14-2-801(5) is waived as applied to APS' non-regulated affiliates to the extent that the UDC is not implicated in any reorganization of the holding company's structure or the non-regulated affiliates' structure. In any reorganization where the UDC is implicated in any manner as to reconfiguration of the holding company's structure or an affiliates' reconfiguration, or if the UDC forms, divests 8 or reconfigures any of its subsidiaries, Rule R14-2-801(5) is not waived and is applicable to APS (UDC). R14-2-804(A) APS has requested a waiver of the rule that requires any affiliate that transacts business with the UDC to open its books and records to Commission review. Staff agrees that R14-2-804(A) may be waived as long as the non-regulated affiliate's books and records reflect transactions with the UDC and are included in the Code of Conduct required by the Electric Competition Rules. By this waiver, the Commission still retains jurisdiction to review and have access to the books and records of affiliates of the UDC for whatever purposes the Commission deems appropriate if the Commission's rate setting jurisdiction is implicated. R14-2-805(A) APS has requested waiver of the rule that requires a holding company to file an annual report with respect to diversification plans and the activities of unregulated subsidiaries. The affect of the waiver requested by APS would be to limit the annual filing requirement to the UDC only. Staff agrees that the annual filing under the rule can be limited to the UDC unless the holding company or subsidiary's activities implicate the UDC, and have a likely material adverse affect upon the UDC's financial viability and integrity. R14-2-805(A)(2) This Rule requires a specific description of business activities of all affiliates to be filed with the Commission on an annual basis. APS wishes to have a waiver of the Rule and limit disclosure to the nature of the business rather than specific activities. Staff agrees this Rule may be waived to the extent indicated by APS. R14-2-805(A)(6) APS seeks a waiver of the disclosure requirement in the annual filing for bases for allocation of all plant revenue expenses to all regulated and unregulated entities in the holding company structure. APS' request limits disclosure to allocations applicable to the UDC. Staff agrees with this waiver to disclosure but reserves the Commission's jurisdiction to receive disclosure of the bases for allocation if necessary in the Commission's determinations in any matter, including but not limited to rate setting matters. 9 R14-2-805(A)(9), (10) and (11) APS seeks a waiver of the annual submission of contracts and agreements for transactions between the regulated utility and nonregulated affiliate. Staff agrees to the waiver of this requirement as requested by APS as to the contracts and agreements which are not covered by the Code of Conduct required by the Retail Competition Rules or not subject to FERC approval. However, the Commission reserves the jurisdiction to receive the information that would have been submitted under the rule, if the Commission deems necessary for any purpose including, but not limited to rate setting matters. XVI. IMPLEMENTATION OF RETAIL ACCESS. Direct access to electric generation suppliers will be phased in for all customers in APS' territory in accordance with A.A.C. R14-2-1604. APS shall determine residential customers eligible for retail access pursuant to the plan filed by APS with the Commission on September 15, 1998. For customers that are 20 kW or smaller at each premise, load profiling will be allowed. XVII. CLARIFICATION OF SERVICES THAT MUST AND CAN BE OFFERED BY APS Staff will support amending A.A.C. R14-2-1616.B, as provided in Exhibit D hereto. XVIII. CONSIDERATION FOR AGREEMENT The Company's willingness to enter into this Agreement and to withdraw from certain civil actions against the Commission is based upon the Commission's irrevocable promise herein to permit recovery of the Company's regulatory assets and stranded costs as provided herein. Such promise by the Commission shall survive the expiration of the Agreement and shall be specifically enforceable against this and any future Commission. MISCELLANEOUS PROVISIONS 1. ADMISSIONS. This Agreement represents an attempt to compromise and settle disputed claims arising out of APS' Applications in a manner consistent with the public interest. Nothing contained in this Agreement is an admission by any of the parties that any of the positions taken, or that might be taken by each in formal proceedings, is unreasonable. In addition, acceptance of this Agreement by the parties is without prejudice to any position taken by any party in these proceedings. 10 2. COMMISSION ACTION. Each provision of this Agreement is in consideration and support of all the other provisions, and expressly conditioned upon acceptance by the Commission without change. In the event that the Commission fails to adopt this Agreement according to its terms by November 25, 1998, this Agreement shall be deemed withdrawn and the parties shall be free to pursue their respective positions in these proceedings without prejudice. 3. LIMITATIONS. The terms and provisions of this Agreement apply solely to and are binding only in the context of the provisions and results of this Agreement and none of the positions taken herein by the parties may be referred to, cited or relied upon by any other party in any fashion as precedent or otherwise in any other proceeding before this Commission or any other regulatory agency or before any court of law for any purpose except in furtherance of the purposes and results of this Agreement. 4. To the extent that any provisions of this Agreement are inconsistent with the Commission's Electric Competition Rules, the provisions of this Settlement Agreement are intended to apply. However, no waivers of any Commission rules are granted to APS except as provided herein. 5. LOW INCOME CUSTOMER PROGRAMS. Prior to Commission consideration of this Settlement Agreement, the parties acknowledge that APS may enter into discussions with others regarding low income customer programs and, as a result, may request Commission recognition of the results of such discussions. 6. PROPOSED ORDER. The proposed form of order acceptable to the parties is contained in Exhibit E, attached hereto. Dated this November 4, 1998 Arizona Public Service Company Arizona Corporation Commission By: William J. Post By: Jack Rose --------------------------- --------------------------- Title: CEO Title: Executive Secretary ------------------------ ------------------------ 11 CALCULATION OF THE MARKET GENERATION CREDIT The Market Generation Credit ("MGC") will be stated as an Off-Peak and an On-Peak value for each calendar month. For all customers less than 1 MW in size, the total monthly dollar credit will be calculated by customer class and will use the same energy consumption profile for each customer within a particular class. The total monthly dollar credit for customers 1 MW or greater will be calculated individually for each customer. All MGC values will be determined in the month of November for the succeeding calendar year. The calculations will be based on the NYMEX forward price curve for the succeeding calendar year and the historical California PX Prices for the preceding year. The MGC values will be grossed up by the distribution Loss Factor as well as the Adder, as such terms are defined below. ON-PEAK MGC = [(NYMEX) * (1 + LOSS FACTOR)] + ADDER OFF-PEAK MGC = [(NYMEX) * (1 + LOSS FACTOR) * (LLR)] + ADDER Where: ADDER: An addendum to the calculated prices designed to promote competition and credit customers for ancillary services. This adder will be set at 0.300(cent) kWh for conforming loads (those with coincident peak load factors equivalent to the aggregate system load factor). This adder will be adjusted by the ratio of system load factor to customer load factor and stated in increments of 5 between 35 percent and 95 percent load factors. LOSS FACTOR: A multiplier designed to reflect the appropriate distribution losses by voltage level. LLR: A light load ratio calculated by dividing the average California Off-Peak price by the average California On-Peak prices for the same month of the preceding year. The California Off-Peak and On-Peak prices will be the hourly day-ahead unconstrained California PX prices. OFF-PEAK: All holidays and hours recognized by the Western Systems Coordinating Council as off-peak periods. ON-PEAK: All non-Off-Peak hours. NYMEX: The Palo Verde electricity futures contract traded on the New York Mercantile Exchange for each month of the following calendar year as determined in November of the preceding year. MONTHLY CUSTOMER TRANSITION CHARGE CALCULATION The monthly Customer Transition Charge (CTC) will be calculated using the following formula: EXHIBIT A CTCS = [(TARIFF GENERATION CHARGES) * (BILLING DETERMINANTS)] - [(MGC +ADDER) * (BILLING DETERMINANTS)] The monthly CTC cannot be less than zero. TRUE-UP OF THE MONTHLY CUSTOMER TRANSITION CHARGE CALCULATION: The difference between the projected monthly NYMEX price as described above and the actual NYMEX price as determined by the average of the last three trading days for that month will be multiplied by that month's competitive direct access sales. This monthly amount will be considered an over- or under- recovery of stranded costs. These differences will then be accumulated (including a return component), and at the end of each calendar year will be divided by the next calendar year's projected competitive direct access sales. The resultant factor (in (cent)/kWh) will be applied to any competitive direct access sales during the following calendar year in order to adjust the CTC for the calculated true-up. Exhibit A MEMORANDUM OF UNDERSTANDING BETWEEN ARIZONA PUBLIC SERVICE COMPANY AND TUCSON ELECTRIC POWER COMPANY The purpose of this memorandum of understanding ("MOU") is to confirm the understanding between ARIZONA PUBLIC SERVICE COMPANY ("APS"), and TUCSON ELECTRIC POWER COMPANY ("TEP") regarding the transaction set forth below. 1. RECITALS: 1.1. In connection with its Application for approval of its Plan for Stranded Cost Recovery filed with the Arizona Corporation Commission ("ACC") pursuant to A.A.C. R-14-2-1607, et. seq., TEP has proposed to divest all of its generation assets, including, without limitation, TEP's interest in the Navajo Generating Station located in Page, Arizona ("Navajo") and the Four Corners Generating Units 4 and 5 located near Farmington, New Mexico ("Four Corners"), all of which are more particularly described on Attachment A ("Generating Assets"); 1.2. APS is willing to divest its 345kV and 500kV transmission system facilities and associated rights of way, which are more particularly described on Attachment B (the "Transmission Assets") only as part of, and conditioned upon, a comprehensive settlement ("APS Settlement Agreement") with the ACC Staff that requires such divestment to a third party, and that satisfactorily resolves a number of competition-related issues, and that is approved by an ACC order in form and substance satisfactory to APS as more fully described below; and 1.3. The Parties desire to outline in this MOU the principles that will form the basis for negotiation of definitive terms and conditions pursuant to which the Parties will exchange TEP's Generation Assets for APS's Transmission Assets (the "Transaction"). 2. EXCHANGE OF ASSETS BETWEEN APS AND TEP: At the Closing, as defined below, APS will transfer to TEP the Transmission Assets and TEP will transfer to APS the Generation Assets. In addition, subject to any consent requirements, APS shall transfer and assign to TEP and TEP shall assume the obligations associated with all existing agreements for transmission service over the Transmission Assets. To the extent there is a difference between the agreed upon fair market values of the Transmission Aassets and Generation Assets, such difference will be paid in the form of cash at Closing, as defined below, by the Party transferring the assets with the lower value. The Transaction shall also include a power purchase agreement providing for unit Page 1 of 6 EXHIBIT B contingent power sales from APS to TEP, as more fully described in Section 6 below ("Power Purchase Agreement"). 3. CLOSING: Subject to the terms and conditions set forth in the Definitive Agreement, the closing of the Transaction (the "Closing") is estimated to be on or before January 2, 2001. To the extent any condition precedent set forth in the Definitive Agreement, including those enumerated in Section 7 of this MOU, has not been satisfied by January 2, 2001, the Closing will be extended by mutual consent of the Parties to a date by which the Parties reasonably believe that such condition precedent will be satisfied. In the event all conditions have not been satisfied or waived by the applicable Party or Parties by December 31, 2002, the Definitive Agreement between the Parties shall terminate. 4. DEFINITIVE AGREEMENT: The completion of the Transaction is subject to the execution by the Parties of an agreement, which will be based on the principles set forth herein and which will include mutually agreeable and comprehensive terms, conditions, representations, warranties, indemnities, and covenants with respect to the Transaction and structure (the "Definitive Agreement") on or before 60 days from the date that the ACC enters both the APS Order and TEP Order, as described herein. The obligation of APS to enter into the Definitive Agreement is subject to the receipt by APS of a final Order, not subject to appeal, which adopts the APS Settlement Agreement , which in form and substance is satisfactory to APS ("APS Order"). The obligation of TEP to enter into the Definitive Agreement is subject to the receipt by TEP of a final Order, not subject to appeal, which adopts a settlement with the ACC regarding TEP's Plan for Stranded Cost Recovery pursuant to A.A.C. R-14-2-1607 et. seq ("TEP Order"). The Parties agree to negotiate in good faith to reach a Definitive Agreement within the 60 day period described above, provided, however, such time may be extended by mutual agreement of the Parties. In the event APS and TEP do not obtain the aforementioned Orders by December 15, 1998, or any mutually agreeable extension thereof, either Party may terminate this MOU by providing written notice to the other Party and neither Party shall have any obligation or liability hereunder. 5. ASSET VALUATION For purposes of the Transaction the value of the Transmission Assets will be the book value at the date of Closing, which is estimated to be approximately $162 million as of July, 1998; and the value of the Generation Assets is $165 million as of January 1, 2001. The fair market values are based on the Transaction being subject to the terms and conditions outlined in this MOU; the asset descriptions contained in Attachments A and B; and assumptions that the physical condition of Page 2 of 6 the Assets will not materially impair their operation or efficiency as of the Closing date. Fair market values will be subject to adjustments based on the final schedule of assets to be transferred; inventories of equipment; and due diligence inspection of the physical condition of the Assets and those rights and obligations to be transferred as part of the Transaction. In the event that any of the Assets cannot be transferred because of the exercise by any third party of a right of first refusal to purchase a portion of such Assets, the fair market value of such Assets shall be adjusted in proportion to the amount of assets being transferred. The above values with respect to the Generation Assets do not include any reserves for reclamation claims through the date of Closing. Such reserves will be funded by a cash payment to APS at Closing, if the amount of such reserves have been definitively determined, or by establishment of an escrow reserve fund to be agreed upon by the parties and to be funded in cash by TEP at Closing. Fuel, material and supplies will be transferred at book value at the time of Closing. 6. POWER PURCHASE AGREEMENT AND TRANSMISSION O&M 6.1. At Closing the parties will enter into a Power Purchase Agreement which will provide for unit contingent power sales from APS to TEP from the Generation Assets. The Power Purchase Agreement will be based on the terms and conditions set forth in Attachment C. 6.2. In negotiating the Definitive Agreement the Parties will discuss the desirability of, and terms and conditions under, which APS would continue to provide certain O&M support functions for the Transmission Assets for a period subsequent to Closing. 7. CONDITIONS PRECEDENT TO CLOSING: 7.1. The Definitive Agreement shall provide that Closing of the Transaction shall be subject to certain conditions, which must be satisfied prior to Closing. Each Party agrees to use its best efforts to satisfy the conditions precedent applicable to it prior to the Closing. In addition to any other conditions the Parties may agree upon, conditions to Closing will include the following: 7.2. MUTUAL CONDITIONS PRECEDENT: 7.2.1. Receipt of any necessary FERC approval of the Transaction, including transfer of transmission assets pursuant to ss. 203 of the Federal Power Act. Page 3 of 6 7.2.2. Receipt of FERC approval of a transmission pricing structure as described in Section 8 of this MOU. 7.2.3. Receipt of any necessary ACC approval of the Transaction. 7.2.4. Any consents or approvals of other regulatory agencies and third Parties necessary to consummate the Transaction as contemplated in the Definitive Agreement. 7.2.5. Absence of any pending or threatened litigation or adverse regulatory proceeding with respect to the APS Order, the TEP Order or the Transaction. 7.2.6. Absence of any material adverse change in the physical condition or value of the Transmission Assets and Generation Assets between the date of the Definitive Agreement and the Closing. 7.3. APS CONDITIONS PRECEDENT 7.3.1. Receipt of such consents or approvals as may be required to effect the transfer of the Transmission Assets, including satisfaction of any rights-of-first-refusal held by the other participants in the Transmission Assets. 7.3.2. Replacement of APS as Operating Agent for the Navajo Project Southern Transmission System, the Four Corners 500kV and 345kV Switchyards, and the Palo Verde/North Gila 500kV line. 7.3.3. Execution of the Power Purchase Agreement by both Parties. 7.3.4. Receipt of satisfactory fairness opinions and/or independent appraisals and approval of its Board of Directors. 7.4. TEP CONDITIONS PRECEDENT 7.4.1. Receipt of such consents or approvals as may be required to effect the transfer of TEP's ownership interest in Four Corners and Navajo, including satisfaction of any rights-of-first-refusal held by the other participants in the Navajo Project and the Four Corners Project. 7.4.2. An order by the ACC which will allow TEP to recover in rates its costs under the Power Purchase Agreement. 7.4.3. Appointment of TEP as Operating Agent for the Navajo Project Southern Transmission System, the Four Corners 500kV and 345kV Switchyards, and the Palo Verde/North Gila 500kV line. Page 4 of 6 7.4.4. Receipt of satisfactory fairness opinions and/or independent appraisals and approval of its Board of Directors. 7.5. All regulatory and third party consents and approvals shall be satisfactory to each Party in form and substance. 8. TRANSMISSION PRICING: In their applications to FERC for approval of the sale of the Transmission Assets and the Open Access Transmission Tariff by which APS will receive service over the Transmission Assets, the Parties will develop and present to FERC a transmission pricing structure for the use of such assets that will not increase rates to customers in the Parties' current service territories. APS will enter into a Service Agreement with TEP relating to APS' use of the Transmission Assets under an Open Access Transmission Tariff accepted by FERC. This Open Access Transmission Tariff shall contain zonal rates developed for the use of EHV transmission facilities pursuant to which the transmission rates for any transmission user in either Party's current service territory, including APS' merchant group, shall not be adversely affected by the transfer of the Transmission Assets. The Tariff will also preserve and recognize the rights of transmission users under their existing transmission agreements with the Parties. Where APS transmission users are receiving service under a single agreement for both the Transmission Assets and the lower voltage transmission assets to be retained by APS, the Parties will agree to bifurcate those obligations in a manner that will not result in any cost shifting or increase in transmission costs to such users or APS. 9. EXCLUSIVITY: unless and until this MOU is terminated pursuant to its terms, and subject to the requirements associated with rights-of-first refusal held by other participants in jointly owned projects in which the Parties are also participants, the Parties shall not, directly or indirectly, solicit or entertain offers from, negotiate with, or in any manner encourage, discuss, accept, or consider any proposal of any other person relating to the acquisition of the Assets, in whole or in part. Notwithstanding the foregoing, the Parties understand and agree that if all or any portion of the Transmission Assets are not transferred to TEP due to a failure to satisfy any of the conditions set forth in Section 7 above or in the Definitive Agreement, APS will, in accordance with the terms of the APS Settlement Agreement, divest those Transmission Assets to a third party upon such terms and conditions as APS, in its sole and absolute discretion, determines to be appropriate and TEP shall not take any action to prevent such divestiture. The Parties further understand and agree that if all or any portion of the Generation Assets are not transferred to APS due to a failure to satisfy any of the conditions set forth in Section 7 above or in the Definitive Agreement, TEP will, in accordance with the terms of the TEP Order, Page 5 of 6 divest those Generation Assets to a third party upon such terms and conditions as TEP, in its sole and absolute discretion, determines to be appropriate and APS shall not take any action to prevent such divestiture 10. CONFIDENTIALITY: The Parties agree to continue to abide by the terms of the Confidentiality Agreement between the Parties dated September 23, 1998. 11. COSTS: Each Party shall be responsible for and bear all of its own costs and expenses (including any broker's or finder's fees and the expenses of its Representatives) incurred at any time in connection with the negotiation of the Definitive Agreement and the pursuit or consummation of the Transaction. 12. ENTIRE AGREEMENT: This MOU constitutes the entire agreement between the Parties, and supersedes all prior oral or written agreements, understandings, representations and warranties, and courses of conduct and dealing between the Parties on the subject matter hereof. Except as otherwise provided herein, this MOU may be amended or modified only by a writing executed by both Parties. 13. SIGNATURE CLAUSE: The signatories hereto represent that they have been appropriately authorized to enter into this Agreement in Principle on behalf of the Party for whom they sign. This MOU is hereby executed as of this 4th day of November, 1998. ARIZONA PUBLIC SERVICE COMPANY By Jack Davis ------------------------------------ Its President ------------------------------------ TUCSON ELECTRIC POWER COMPANY By Vincent Nitido ------------------------------------ Its Vice President ------------------------------------ Page 6 of 6 ATTACHMENT A Generation Assets of TEP NAVAJO GENERATING STATION All of Tucson Electric Power Company's right, title, interest, and assets in the Navajo Project and the Navajo Project Agreements including, but not limited to, those specific interests as set forth in Sections 5.19, 6 and 7 of the Navajo Project Co-Tenancy Agreement, as amended; excluding therefrom, however, any right, title, and interest in facilities or agreements relating to the transmission of electricity in excess of 230kV from the Navajo Generating Station. 1. Adequate SO2 allowances to operate the generation facilities for their remaining life. 2. Three steam electric generating units (Unit 1, Unit 2 and Unit 3), each of which shall have a nameplate rating of 750,000 kw and shall be a tandem-compound, four flow, single reheat, turbine-generator unit with initial steam conditions of 3500 psig and 1000(degree) F, including three pulverized coal-fired, super-critical steam generator units. 3. All auxiliary equipment associated with said units. 4. An administration building, machine shop and warehouse to be located adjacent to the power plant. 5. A pumping station and all associated equipment to be located on the Colorado River. 6. 500 kv step-up transformers and all equipment associated therewith up to the point where the leads from the said transformers terminate at the generator isolating 500 kv disconnect switch structures in the Navajo 500 kv Switchyard. 7. Standby auxiliary power transformation equipment and related facilities. 8. Plant control and communication facilities and associated buildings or equipment. 9. Railroad approximately 80 miles in length extending from within the Rail Loading Site into the Navajo Plant Site, rolling stock, related facilities and equipment. 10. All improvements owned by the Co-Tenants within the Ash Disposal Area, Pumping Plant Site and Rail Loading Site. 11. All land and land rights acquired under the Indenture of Lease, the ss.323 Grants and the Contract and Grant of Easement from the United States for Water Intake and Discharge Facilities. FOUR CORNERS GENERATING STATION All of Tucson Electric Power Company's right, title, interest, and assets in the Enlarged Four Corners Generating Station and the Four Corners Project Agreements including, but not limited to, those specific interests as set forth in Sections 6, 7, and 8 of the Four Corners Project Co-Tenancy Agreement, as amended; excluding therefrom, however, any right, title, and interest in facilities or agreements relating to the transmission of electricity in excess of 230kV from the Enlarged Four Corners Generating Station. All SO2 allowances allotted to TEP's interest in the Four Corners Project. Steam Electric Generating Units 4 and 5 and their associated switchyard facilities shall consist principally of two 755 mw class 3500 psig, 1000 F with reheat to 1000 F, cross-compound, 3600/1800 rpm, double flow, outdoor turbine-generator units, complete with accessories; two pressurized type, super-critical-pressure steam generating units, designed for burning pulverized coal as primary fuel with natural gas available for ignition fuel, complete with accessories; 345-500 kV tie transformers; reserve auxiliary power source; and other items required for the complete generating installation, excluding the Common Facilities and Related Facilities allocated thereto. COMMON FACILITIES FOR ENLARGED FOUR CORNERS GENERATING STATION: 1. Land Rights, including Lease Payments during Construction, Right-of-Way Expense and Surveys. 2. Clearing Site of Brush and Rough Grading. 3. Landscaping and Planting Adjacent to Service Building. 4. Yard Finish Grading of Plant Areas not Requiring Paving or Gravel Surfacing. 5. Plant Access Road, including Subbase, Surfacing, Auxiliary Dike, Culverts and Asphalt Coat from San Juan Bridge to BIA Canal. 6. River Access Road, including Subbase, Gravel Surfacing, Pipeline Bridge Crossing, Culverts and Riprap. 7. Plant Area Roads, including Asphaltic Surfaced, Gravel Based and Other Gravel Surfaced Roads. 8. Cement and Asphaltic Paving in Operating and Parking Areas, including Curbing. 9. Concrete Walks at the Service Building, Warehouse and Circulating Water Intake Area. 10. Plant Area Chain Link Fence, Remote Controlled Main Gate, Manual Gates and Barbed Wire Fence. 11. Yard Lighting Standards, Conduit, Cable, Foundations and Lamps. 12. Fire Protection Pumps, Piping with Excavation and Backfill, Valves, Hydrants and Hose Carts with Hoses and Nozzles. 13. Sanitary Sewer System, including Cast Iron and Clay Sewer Lines, Manholes, Septic Tank and Accessories. 14. Service Water System Chlorinator, Coagulator, Filters, Pumps, Yard Piping, Foundations and Domestic Water Lines. 15. Service and Shop Building Foundation, Walls, Doors, Windows, Heating and Ventilating Equipment, Plumbing, Toilet Facilities and Lighting. 16. Warehouse Foundation, Floor Slab Superstructure and Lighting. 17. Miscellaneous Buildings, Foundations, Floor Slabs, Superstructures and Lighting. 18. Coal Mobile Equipment, includes Hough D500 Paydozer. 19. Cooling Pond Dam, Spillway, Blowdown Structure, Intake Canal, Curtain Wall and Temperature Recorders. 20. Concrete Intake Structure Excavation, Backfill, Caissons and Concrete Structure for Service Water Pumps and Fire Pumps. 21. Hoist Structure and Hoist for Intake Area. 22. Screens and Stoplogs for Service Water and Fire Pumps. 23. Miscellaneous Equipment for Service Water and Fire Pumps. 24. Concrete Cribbing between Intake Structure and Canal Bank. 25. Circulating Water Discharge Canal to Cooling Pond. 26. River Pumping Plant, includes River Weir, Sluiceway, Pump Chamber, Gates, Stoplogs, Pumps, Motors, Lube Water Cooling System, Freeze Protection, Switchgear, Motor Control Center, Transformers, Lighting, Equipment Building, 69-kv Transmission Line, Power Supply, Fence, Gates, Make-up Water Line, Metering Station and Canal. 27. Circulating and Service Water Intake Motor Control Center. 28. General Services Transformers for Area Lighting, Service Water Pump No. 2, Freeze Protection, Fire Booster Pump, etc. 29. Intake Area Transformer for Water Treatment Building, Fire Pump No. 1 Service Water Pumps No. 1 and No. 3, Service Building, Area Lighting, Freeze Protection, etc. 30. Station Lighting Transformers. 31. Station Grounding and Cathodic Protection Systems, including Rectifier, Anode Bed, Ground Rods and Ground Cable. 32. Freeze Protection Strip and Unit Heaters, Heating Cables, Controls and Panels. 33. Underground Manholes, Handholes and Conduit, including Excavation, Backfill and Concrete Envelope. 34. Miscellaneous Power Plant Equipment, including Portable Cranes and Hoists, Fire Extinguishers, Vacuum Cleaner, Weather Station, Office Equipment, Garage Equipment, Stores Equipment, Shop Equipment, Laboratory Equipment, Small Tools, Kitchen Equipment, Testing Equipment and Forklift. 35. 69-kv and 230-kv Switchyard Common to River Pumping Station, including Portion of Site Improvement, Structures, Bus Conductors, Transformers, Oil Circuit Breakers, Air Switches, Lighting Protection, Panels, Wiring, Conduits, Ducts, Manholes, Grounding and Shielding. 36. ntra-site Communication (Gai-tronic and PAX Telephones Service Common Facilities). 37. Spare Parts for Above Facilities. RELATED FACILITIES: 1. COAL HANDLING SYSTEM From the point of the Utah Mining termination at the surge bins down to the gates in the bottom of the bins, including chutes, gates, motor control center enclosure, and surge bins. Includes writing, lighting, foundations, dust control, CO2 blanketing, electrical feed and control, structure, stairs and platforms. 2. MACHINE SHOP STRUCTURE Structure, foundation, lighting, wiring, doors, heating and ventilating equipment, and plumbing, toilet, and shower facilities. 3. MODIFICATIONS TO SERVICE BUILDING Structural changes, walls, doors, windows, heating and ventilating equipment, lighting, and wiring. 4. VEHICLE BRIDGE OVER INTAKE CANAL Structure, guard rail, pipe supports and surfacing. 5. REROUTE ACCESS ROAD THROUGH UNITS 4 AND 5 AREA Subbase, base material, surfacing and culverts. 6. MODIFICATIONS TO RIVER PUMPING STATION AND MAKE-UP PIPELINE Structures, foundations, pumps, motors, electrical supply facilities, valves, piping and control apparatus for pump station and relocated section of 36-inch make-up pipeline, new 2-inch pipeline for river pump packing gland water, paving of roads and parking area and barricades for protection from earth slides. 7. MOBILE EQUIPMENT MAINTENANCE BUILDING Foundation, floor slab, superstructure and lighting and repair equipment. 8. MISCELLANEOUS POWER PLANT EQUIPMENT Small tools, machine shop tools, laboratory equipment, lockers, bins, shelving, portable fire fighting equipment, etc. 9. ENLARGEMENT OF DISCHARGE CANAL Excavation to enlarge channel for discharging circulating water to lake and protection from erosion of channel walls. 10. COMBUSTIBLES STORAGE BUILDING Foundation, floor slab, repairs to superstructure, and lighting. 11. STATION MOBILE EQUIPMENT Hydraulic crane, forklift trucks, small electric vehicles, and bicycles. 12. PLANT ACCESS ROAD Access road, including subbase preparation, base material, asphalt surfacing, culverts and drainage facilities from BIA Canal to the station gate. 13. COAL SAMPLING BUILDING AND EQUIPMENT Sampling building structure from point of connection with the surge bin structure including foundations, stairs, lighting, power facilities, dust control facilities, hearing and ventilating sampling equipment, sample preparation room with furnishings. 14. WIND VELOCITY AND DIRECTION INSTRUMENTS Wind velocity and direction instruments, wiring conduit and recorders. 15. RIVER WATER SOLIDS MEASURING EQUIPMENT Flow recorder, conductivity recorder and cells, conduit, wiring and supports. 16. WAREHOUSE Structure, floor slab, lighting, heating and ventilating equipment, plumbing and office facilities. 17. NEW ADMINISTRATION BUILDING Structure, foundation, lighting, windows, heating and ventilating equipment. 18. GUARDHOUSE - MAIN AND SATELLITE Structure, foundation, lighting, doors, heating and ventilating equipment. 19. SWITCHYARD SHOP Structures, foundation, lighting, doors, heating and ventilating equipment and office facilities. 20. SHOP 4 & 5 Structure, foundation, lighting, wiring, doors, heating and ventilating equipment, plumbing, toilet and shower facilities and office facilities. 21. COMMON BUILDING Structure, foundation, lighting, wiring, doors, heating and ventilating equipment, plumbing, toilet and shower facilities, office facilities and lunch room facilities. 22. OVERHAUL SHOP Structure, foundation, lighting, wiring, doors, heating and ventilating equipment, plumbing, toilet facilities and office facilities. 23. 150 GALLON DEMINERALIZER Structure, foundation, pumps, motors, electrical supply facilities and water treatment facilities. 24. NATIONAL POLLUTION DISCHARGE ELIMINATION SYSTEM (NPDES) TRENCH Excavated canal and concrete lined trench. 25. BRINE CONCENTRATOR AND RELATED CAPITAL IMPROVEMENTS The brine concentrator and the capital improvements related thereto are part of the SO2 removal project for Units 4 and 5 including the separator blowdown line and the chemical cleaning piping. ATTACHMENT B TRANSMISSION ASSETS 1. Cholla/Saguaro 500kV Line and rights-of-way 2. Cholla 500kV/345kV Switchyard and land rights 3. Saguaro 500kV Substation and land rights 4. Two Four Corners/Pinnacle Peak 345kV Lines and rights-of-way 5. Undivided interest in Four Corners345kV Switchyard and Project Agreements 6. Undivided interest in Pinnacle Peak 345kV Substation and land rights 7. Undivided interest in Four Corners 500kV Switchyard and Project Agreements 8. Preacher Canyon 345kV Substation and land rights 9. Undivided interest in Two Navajo/Westwing 500kV Lines, Project Agreements and land rights 10. Undivided interest in Navajo 500kV Switchyard, Project Agreements, and land rights 11. Undivided interest in Westwing 500kV Switchyard, Project Agreements, and land rights 12. Undivided interest in Yavapai 500kV Substation, Project Agreements, and land rights 13. Navajo Project breakers in Moenkopi 500kV Switchyard and Project Agreements 14. Navajo Project breakers, series capacitors, and a line reactor in the Moenkopi Switchyard 15. Undivided interest in Two Palo Verde/Westwing 500kV Lines, agreements, and rights-of-way 16. Undivided interest in Palo Verde 500kV Switchyard, agreements, and land rights 17. Undivided interest in Interconnection Agreement with Westwing 500kV Switchyard Participants 18. Undivided interest in Palo Verde/Kyrene 500kV Line, agreements, and rights-of-way 19. Undivided interest in Palo Verde/North Gila 500kV Line, agreements, and rights-of-way 20. Undivided interest in Interconnection Agreement with Palo Verde 500kV Switchyard Participants 21. Undivided interest in North Gila 500kV Substation, agreements, and land rights 22. Undivided interest in Mead/Phoenix 500kV Line, Project Agreements, and rights-of-way 23. Undivided interest in Perkins 500kV Substation, Phase Shifter, agreements, and land rights 24. Undivided interest in Mead 500kV Substation, agreements and land rights 25. Undivided interest in Marketplace 500kV Switchyard, agreements and land rights 26. Undivided interest in Market Place-Mead/Market Place - McCullough 500kV Line, agreements, and rights-of-way 27. Undivided interest in McCullough 500kV Switchyard, agreements, and land rights 28. Four Corners/El Dorado 500kV Line, Moenkopi Switchyard, Transmission Service Agreement with Southern California Edison Company, and rights-of-way 29. At substations, the ownership transition is at the high side of the transformer, except Pinnacle Peak and Four Corners. ATTACHMENT C POWER PURCHASE AGREEMENT TERMS SHEET PURCHASER: Tucson Electric Power Company SELLER: Arizona Public Service Company AMOUNT: 200MW TERM: 4 years, beginning January 1, 2001 AVERAGE PRICE: $/MWh ----- 2001 $31 2002 $32 2003 $33 2004 $35 Price to be shaped on an on-peak/off-peak basis, based on a minimum load factor of 80% on-peak and 80% off-peak and a maximum load factor which will be determined by mutual agreement of the parties in the Power Purchase Agreement. The Seller may also offer pricing for the purchase of power in excess of the agreed maximums. The Power Purchase Agreement will also allow the minimum obligations, or capacity scheduled absent energy, to be satisfied through the payment of dollars. The minimum annual load factor shall be 80%. CONTINGENCY: The 200MW will be pro-rated over the three Navajo Generating Station Units and the two Four Corners Project Units, and the availability of power and energy to Purchaser under the Power Purchase Agreement will be contingent on the operation of each of the five units at a level sufficient to provide its allocated share of the 200MW ("Unit Availability"). SCHEDULING: The Power Purchase Agreement will include monthly minimum and maximum capacity factors for scheduling purposes. The Purhcaser will have the right to schedule capacity and/or energy on an hourly basis pursuant to the pricing concepts described above. BALANCING ACCOUNT: A year-to-year balancing account will be maintained through which any short falls in energy taken by Purchaser during a calendar year will roll over into the following calendar year at the previous year's price. CHANGES TO 1996 RATE REDUCTION AGREEMENT MOOT SECTIONS (Not Extended by Instant Agreement):1 Sections 1, 5, 7, 8, 10, 11, 14 MODIFIED SECTIONS (Extended by Instant Agreement with Modifications): Sections 2, 4, 6, 9, 12, 13 NON-MODIFIED SECTIONS (Extended by Instant Agreement without Modification):2 Sections 3, 15-17 - --------------------------- 1 This includes Sections referring to specific one-time obligations that have either been fulfilled or which will be fulfilled under terms of the 1996 Agreement without extension. It also includes sections that have already been superseded by a subsequent Commission order or orders. 2 Or, alternatively, sections of the 1996 Rate Reduction Agreement that would have extended beyond the end of the rate mechanism/rate moratorium provisions in 1999 irrespective of this Agreement. EXHIBIT C R14-2-1616 B. Beginning January 1, 1999, an Affected Utility or Utility Distribution Company shall not provide competitive services as defined herein, except as otherwise authorized by these rules or by the Commission. However, this rule does not preclude an Affected Utility's or Utility Distribution Company's affiliate from providing competitive services. Nor does this rule preclude an Affected Utility or Utility Distribution Company from billing its own customers for distribution service, or from providing billing services to Electric Service Providers in conjunction with its own billing or from providing meters for Load Profiled residential customers. Nor does this rule require an Affected Utility or Utility Distribution Company to separate such assets or services utilized in these circumstances. Affected Utilities and Utility Distribution Companies shall provide, if requested by an ESP or customer, metering, meter reading, billing, and collection services within their service territories at tariffed rates to customers that do not have access to these services, during the years 1999 and 2000, subject to the following limitations. The Affected Utilities and Utility Distribution Companies shall be allowed to continue to provide metering and meter reading services within their service territories at tariffed rates until such time as two competitive ESPs are offering such services to a particular customer class. When two competitive ESPs are providing such services to a particular customer class, the Affected Utilities and Utility Distribution Companies will no longer be allowed to offer the services(s) to new competitive customers in that customer class, but may continue to offer the services(s) through December 31, 2000, to the existing competitive customers signed up prior to the commencement of service by the two competitive ESPs. Exhibit D BEFORE THE ARIZONA CORPORATION COMMISSION JIM IRVIN Commissioner-Chairman RENZ D. JENNINGS Commissioner CARL J. KUNASEK Commissioner IN THE MATTER OF THE APPLICATION ) DOCKET NO. E-01345A-98-0473 OF ARIZONA PUBLIC SERVICE ) COMPANY FOR APPROVAL OF ITS ) RECOVERY ) ) - -------------------------------------) ) IN THE MATTER OF THE FILING OF ) DOCKET NO. E-01345A-97-0773 ARIZONA PUBLIC SERVICE COMPANY ) PURSUANT TO A.A.C. R14-2-1601 ET SEQ.) ) - -------------------------------------) ) IN THE MATTER OF COMPETITION IN ) DOCKET NO. RE-00000C-94-0165 THE PROVISION OF ELECTRIC ) SERVICES THROUGHOUT THE STATE ) Decision No. _____________ OF ARIZONA. ) ) ORDER - -------------------------------------) Open Meeting - ---------------- Phoenix, Arizona FINDINGS OF FACT ---------------- 1. Arizona Public Service Company ("APS") is an Arizona corporation providing electric utility service within the State of Arizona. 2. The rates and charges currently in effect for APS were determined to be just and reasonable in Decision No. 59601, as modified by Decision Nos. 60216, 60225 and 61103. Decision No. 59601 approved a Settlement Agreement between Staff and APS which reduced rates. 3. On February 15, 1998, APS filed its proposal for unbundled tariffs. 4. On August 21, 1998, APS filed its proposal for stranded cost recovery. 5. Staff and APS have reached agreement on a number of interrelated issues in the above dockets. 6. The particulars of the agreement are memorialized in a written Settlement Agreement ("Agreement") dated ____________. Staff and APS filed the Agreement with the Exhibit E DOCKET NO. E-01345A-98-0473 E-01345A-97-0773 RE-00000C-94-0165 Commission and provided all parties in the above dockets with copies of the Agreement and proposed Order at the time of filing. 7. A procedural order governing the conduct of this proceeding was issued. The procedural order did the following: required that APS provide notice by publication (or other media) of the hearings in these matters, and established procedures for intervention; established procedures for discovery; established dates for Staff, APS and intervenors to file testimony or comments; and set a hearing date at which all parties would be able to present witnesses and evidence and cross-examine the witnesses of other parties. 8. All intervenors had the opportunity to file testimony or comments regarding the Agreement, and to present witnesses and exhibits and to cross-examine witnesses presented by other parties. 9. Commencing on _________, a hearing was held on these matters at the Commission's offices in Phoenix, Arizona. 10. Staff and APS believe that the Agreement they have reached is consistent with the best interests of the parties and the public interest generally. A copy of the Agreement is attached hereto as Exhibit "A". CONCLUSIONS OF LAW ------------------ 1. APS is a public service corporation within the meaning of Article 15 of the Arizona Constitution and Title 40 of the Arizona Revised Statutes. 2. The Commission has jurisdiction over APS, over the subject matter of these proceedings, and over the Agreement submitted by the Staff and APS. 3. APS provided notice of this matter in accordance with law. 4. The Agreement resolves all matters contained therein in a manner which is just and reasonable, and which promotes the public interest. 5. The Commission's acceptance and approval of the terms of the Agreement between Staff and APS are in the public interest. 6. The rates and charges contained in the Agreement are just and reasonable. DECISION NO._______________ 2 Exhibit E DOCKET NO. E-01345A-98-0473 E-01345A-97-0773 RE-00000C-94-0165 7. APS should be directed to file tariffs consistent with the Agreement and the findings contained herein. 8. The waivers and approvals agreed to in the Agreement should be approved. ORDER ----- IT IS THEREFORE ORDERED that this Order incorporates the Agreement executed between APS and Staff, and such Order is expressly conditioned thereon. IT IS FURTHER ORDERED that the terms and conditions of the Agreement be and the same are hereby adopted and approved. IT IS FURTHER ORDERED that the waivers and approvals agreed to in the Agreement are hereby approved. IT IS FURTHER ORDERED that APS is authorized and directed to file schedules of rates and charges consistent with the Findings and Conclusions of this Order. IT IS FURTHER ORDERED that this Order shall become effective immediately. BY ORDER OF THE ARIZONA CORPORATION COMMISSION ________________________________________________________________________________ Commissioner-Chairman Commissioner Commissioner IN WITNESS WHEREOF, I, JACK ROSE, Executive Secretary of the Arizona Corporation Commission, have hereunto, set my hand and caused the official seal of this Commission to be affixed at the Capitol, in the City of Phoenix, this ___ day of _____________ 1998. _______________________________________ JACK ROSE Executive Secretary DISSENT__________________ DECISION NO._______________ 3 Exhibit E -----END PRIVACY-ENHANCED MESSAGE-----