0000950147-01-501810.txt : 20011119 0000950147-01-501810.hdr.sgml : 20011119 ACCESSION NUMBER: 0000950147-01-501810 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20010930 FILED AS OF DATE: 20011106 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: 1934 Act SEC FILE NUMBER: 001-04473 FILM NUMBER: 1775476 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 e-7654.txt QUARTERLY REPORT FOR THE QTR ENDED 09/30/2001 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, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from __________ to __________ Commission file number 1-4473 ARIZONA PUBLIC SERVICE COMPANY (Exact name of registrant as specified in its charter) Arizona 86-0011170 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 400 N. Fifth Street, P.O. Box 53999, Phoenix, Arizona 85072-3999 (Address of principal executive offices) (Zip Code) (602) 250-1000 (Registrant's telephone number, including area code) (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 5, 2001: 71,264,947 THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(A) AND (B) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM WITH THE REDUCED DISCLOSURE FORMAT. Glossary ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission ADEQ - Arizona Department of Environmental Quality APS Energy Services - APS Energy Services Company, Inc., a Pinnacle West subsidiary Bookout - one party appears more than once in a contract path for the purchase and sale of a commodity, resulting in an unplanned net settlement CC&N - Certificate of Convenience and Necessity Citizens - Citizens Communications Company Company - Arizona Public Service Company EITF - Emerging Issues Task Force El Paso - El Paso Natural Gas Company FASB - Financial Accounting Standards Board FERC - United States Federal Energy Regulatory Commission Four Corners - Four Corners Power Plant ISO - California Independent System Operator MW - megawatt, one million watts 1999 Settlement Agreement - comprehensive settlement agreement related to the implementation of retail electric competition Native Load - retail and wholesale sales supplied under traditional cost-based rate regulation Palo Verde - Palo Verde Nuclear Generating Station PG&E - PG&E Corp. Pinnacle West - Pinnacle West Capital Corporation Pinnacle West Energy - Pinnacle West Energy Corporation, a Pinnacle West subsidiary PPA - Purchase Power Agreement between Arizona Public Service Company and Pinnacle West PX - California Power Exchange RTO - regional transmission organization Rules - ACC retail electric competition rules Salt River Project - Salt River Project Agricultural Improvement and Power District SCE - Southern California Edison Company SFAS - Statement of Financial Accounting Standards 2000 10-K - Arizona Public Service Company Annual Report on Form 10-K for the fiscal year ended December 31, 2000 -2- PART I - FINANCIAL INFORMATION Item 1. Financial Statements ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Three Months Ended September 30, -------------------------- 2001 2000 ----------- ----------- (Dollars in Thousands) ELECTRIC OPERATING REVENUES ......................................... $ 1,048,634 $ 1,565,622 ----------- ----------- PURCHASED POWER AND FUEL COSTS: Purchased power ................................................... 505,867 977,103 Fuel for electric generation ...................................... 81,751 99,460 ----------- ----------- Total .......................................................... 587,618 1,076,563 ----------- ----------- OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .............. 461,016 489,059 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding purchased power and fuel costs 120,762 110,676 Depreciation and amortization ..................................... 105,771 112,848 Income taxes ...................................................... 70,017 80,317 Other taxes ....................................................... 29,327 25,629 ----------- ----------- Total .......................................................... 325,877 329,470 ----------- ----------- OPERATING INCOME .................................................... 135,139 159,589 ----------- ----------- OTHER INCOME (DEDUCTIONS): Income taxes ...................................................... 1,752 1,446 Other - net ....................................................... (1,650) (3,599) ----------- ----------- Total .......................................................... 102 (2,153) ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS ................................... 135,241 157,436 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt ........................................ 29,211 33,681 Interest on short-term borrowings ................................. 1,331 1,634 Debt discount, premium and expense ................................ 666 566 Capitalized interest .............................................. (3,523) (2,676) ----------- ----------- Total .......................................................... 27,685 33,205 ----------- ----------- INCOME BEFORE ACCOUNTING CHANGE ..................................... 107,556 124,231 Cumulative Effect of a Change in Accounting for Derivatives - net of income taxes of $8,099 ................................... (12,446) -- ----------- ----------- NET INCOME .......................................................... $ 95,110 $ 124,231 =========== ===========
See Notes to Condensed Financial Statements. -3- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Nine Months Ended September 30, -------------------------- 2001 2000 ----------- ----------- (Dollars in Thousands) ELECTRIC OPERATING REVENUES ......................................... $ 2,875,045 $ 2,730,997 ----------- ----------- PURCHASED POWER AND FUEL COSTS: Purchased power ................................................... 1,315,465 1,259,151 Fuel for electric generation ...................................... 325,208 230,972 ----------- ----------- Total .......................................................... 1,640,673 1,490,123 ----------- ----------- OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .............. 1,234,372 1,240,874 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding purchased power and fuel costs 356,355 323,485 Depreciation and amortization ..................................... 314,110 321,642 Income taxes ...................................................... 156,425 163,669 Other taxes ....................................................... 80,071 76,606 ----------- ----------- Total .......................................................... 906,961 885,402 ----------- ----------- OPERATING INCOME .................................................... 327,411 355,472 ----------- ----------- OTHER INCOME (DEDUCTIONS): Income taxes ...................................................... (33) 1,615 Other - net ....................................................... 1,915 (4,021) ----------- ----------- Total .......................................................... 1,882 (2,406) ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS ................................... 329,293 353,066 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt ........................................ 93,031 99,626 Interest on short-term borrowings ................................. 3,807 6,754 Debt discount, premium and expense ................................ 2,001 1,411 Capitalized interest .............................................. (11,347) (7,582) ----------- ----------- Total .......................................................... 87,492 100,209 ----------- ----------- INCOME BEFORE ACCOUNTING CHANGE ..................................... 241,801 252,857 Cumulative Effect of a Change in Accounting for Derivatives - net of income taxes of $9,892 ................................... (15,201) -- ----------- ----------- NET INCOME .......................................................... $ 226,600 $ 252,857 =========== ===========
See Notes to Condensed Financial Statements. -4- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF INCOME (Unaudited)
Twelve Months Ended September 30, -------------------------- 2001 2000 ----------- ----------- (Dollars in Thousands) ELECTRIC OPERATING REVENUES ......................................... $ 3,624,300 $ 3,230,874 ----------- ----------- PURCHASED POWER AND FUEL COSTS: Purchased power ................................................... 1,603,778 1,353,477 Fuel for electric generation ...................................... 425,510 295,842 ----------- ----------- Total .......................................................... 2,029,288 1,649,319 ----------- ----------- OPERATING REVENUES LESS PURCHASED POWER AND FUEL COSTS .............. 1,595,012 1,581,555 ----------- ----------- OTHER OPERATING EXPENSES: Operations and maintenance excluding purchased power and fuel costs 462,962 447,179 Depreciation and amortization ..................................... 417,947 422,739 Income taxes ...................................................... 192,733 184,667 Other taxes ....................................................... 103,195 100,177 ----------- ----------- Total .......................................................... 1,176,837 1,154,762 ----------- ----------- OPERATING INCOME .................................................... 418,175 426,793 ----------- ----------- OTHER INCOME (DEDUCTIONS): Income taxes ...................................................... 2,664 9,398 Other - net ....................................................... (4,921) (11,814) ----------- ----------- Total .......................................................... (2,257) (2,416) ----------- ----------- INCOME BEFORE INTEREST DEDUCTIONS ................................... 415,918 424,377 ----------- ----------- INTEREST DEDUCTIONS: Interest on long-term debt ........................................ 127,836 133,469 Interest on short-term borrowings ................................. 4,508 8,247 Debt discount, premium and expense ................................ 2,695 1,866 Capitalized interest .............................................. (14,659) (7,540) ----------- ----------- Total .......................................................... 120,380 136,042 ----------- ----------- INCOME BEFORE ACCOUNTING CHANGE ..................................... 295,538 288,335 Cumulative Effect of a Change in Accounting for Derivatives - net of income taxes of $9,892 ................................... (15,201) -- ----------- ----------- NET INCOME .......................................................... $ 280,337 $ 288,335 =========== ===========
See Notes to Condensed Financial Statements. -5- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS ASSETS (Unaudited) September 30, December 31, 2001 2000 ----------- ----------- (Dollars in Thousands) UTILITY PLANT: Electric plant in service and held for future use $ 8,053,950 $ 7,805,025 Less accumulated depreciation and amortization ... 3,337,314 3,187,328 ----------- ----------- Total ......................................... 4,716,636 4,617,697 Construction work in progress .................... 255,628 245,749 Nuclear fuel, net of amortization ................ 54,853 47,389 ----------- ----------- Utility plant - net ........................... 5,027,117 4,910,835 ----------- ----------- INVESTMENTS AND OTHER ASSETS ..................... 258,138 269,678 ----------- ----------- CURRENT ASSETS: Cash and cash equivalents ........................ 14,947 2,609 Trust fund for bond redemption ................... 72,370 -- Accounts receivable: Service customers ............................. 408,843 422,012 Other ......................................... 139,000 48,711 Allowance for doubtful accounts ............... (2,821) (2,380) Accrued utility revenues ......................... 102,951 74,566 Materials and supplies, at average cost .......... 81,304 71,966 Fossil fuel, at average cost ..................... 24,833 19,405 Deferred income taxes ............................ 5,793 5,793 Assets from risk management and trading activities 13,800 17,506 Other ............................................ 38,665 38,414 ----------- ----------- Total current assets .......................... 899,685 698,602 ----------- ----------- DEFERRED DEBITS: Regulatory assets ................................ 370,943 469,867 Unamortized debt issue costs ..................... 11,647 12,805 Other ............................................ 52,832 37,928 ----------- ----------- Total deferred debits ......................... 435,422 520,600 ----------- ----------- TOTAL ......................................... $ 6,620,362 $ 6,399,715 =========== =========== See Notes to Condensed Financial Statements. -6- ARIZONA PUBLIC SERVICE COMPANY CONDENSED BALANCE SHEETS LIABILITIES (Unaudited)
September 30, December 31, 2001 2000 ----------- ---------- (Dollars in Thousands) CAPITALIZATION: Common stock .......................................... $ 178,162 $ 178,162 Additional paid-in capital ............................ 1,246,804 1,246,804 Retained earnings ..................................... 793,901 694,802 Accumulated Other Comprehensive Loss .................. (66,609) -- ----------- ---------- Common stock equity ................................ 2,152,258 2,119,768 Long-term debt less current maturities ................ 1,620,523 1,806,908 ----------- ---------- Total capitalization ............................... 3,772,781 3,926,676 ----------- ---------- CURRENT LIABILITIES: Commercial paper ...................................... 174,500 82,100 Current maturities of long-term debt .................. 375,266 250,266 Accounts payable ...................................... 227,149 267,999 Accrued taxes ......................................... 305,842 106,515 Accrued interest ...................................... 16,484 39,488 Customer deposits ..................................... 27,169 24,498 Liabilities from risk management and trading activities 44,107 37,179 Other ................................................. 90,758 104,947 ----------- ---------- Total current liabilities .......................... 1,261,275 912,992 ----------- ---------- DEFERRED CREDITS AND OTHER: Deferred income taxes ................................. 1,010,539 1,110,437 Unamortized gain - sale of utility plant .............. 65,204 68,636 Customer advances for construction .................... 68,763 40,694 Other ................................................. 441,800 340,280 ----------- ---------- Total deferred credits and other ................... 1,586,306 1,560,047 ----------- ---------- COMMITMENTS AND CONTINGENCIES (Notes 6, 7, and 9) TOTAL .............................................. $ 6,620,362 $6,399,715 =========== ==========
See Notes to Condensed Financial Statements. -7- ARIZONA PUBLIC SERVICE COMPANY CONDENSED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, ---------------------- 2001 2000 --------- --------- (Dollars in Thousands) Cash Flows from Operating Activities: INCOME BEFORE ACCOUNTING CHANGE .................... $ 241,801 $ 252,857 Items not requiring cash: Depreciation and amortization .................... 314,110 321,642 Nuclear fuel amortization ........................ 22,221 23,139 Deferred income taxes - net ...................... (46,664) (73,729) Changes in certain current assets and liabilities: Accounts receivable - net ........................ (76,679) (446,059) Accrued utility revenues ......................... (28,385) (38,396) Materials, supplies and fossil fuel .............. (14,766) 3,787 Other current assets ............................. (251) (8,439) Accounts payable ................................. (46,542) 298,198 Accrued taxes .................................... 199,327 145,999 Accrued interest ................................. (23,004) (8,699) Other current liabilities ........................ (11,518) 24,350 Risk management and trading activities - net ..... (14,116) 17,934 Other - net ........................................ 14,733 26,619 --------- --------- Net cash flow provided by operating activities .. 530,267 539,203 --------- --------- Cash Flows from Investing Activities: Trust fund for bond redemption ..................... (72,370) -- Capital expenditures ............................... (324,878) (278,282) Capitalized interest ............................... (11,347) (7,582) Other .............................................. (12,370) 18,349 --------- --------- Net cash flow used for investing activities .... (420,965) (267,515) --------- --------- Cash Flows from Financing Activities: Long-term debt ..................................... -- 300,000 Short-term borrowings - net ........................ 92,400 (36,300) Dividends paid on common stock ..................... (127,500) (127,500) Repayment and reacquisition of long-term debt ...... (61,864) (352,000) --------- --------- Net cash flow used for financing activities .... (96,964) (215,800) --------- --------- Net increase in cash and cash equivalents ............ 12,338 55,888 Cash and cash equivalents at beginning of period ..... 2,609 7,477 --------- --------- Cash and cash equivalents at end of period ........... $ 14,947 $ 63,365 ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the period for: Interest (excluding capitalized interest) ........ $ 108,842 $ 96,723 Income taxes ..................................... $ 41,705 $ 133,817
See Notes to Condensed Financial Statements. -8- ARIZONA PUBLIC SERVICE COMPANY NOTES TO CONDENSED FINANCIAL STATEMENTS 1. Our unaudited Condensed Financial Statements reflect all adjustments which we believe are necessary for the fair presentation of our financial position and results of operations for the periods presented. These adjustments are of a normal recurring nature with the exception of the cumulative effect of a change in accounting for derivatives (see Note 10). We suggest that these Condensed Financial Statements and Notes to Condensed Financial Statements be read along with the Financial Statements and Notes to Financial Statements included in our 2000 10-K. We have reclassified certain prior period amounts to conform to current period presentation. 2. Weather conditions and trading and wholesale power marketing activities can have significant impacts on our results for interim periods. Results for interim periods do not necessarily represent results to be expected for the year. 3. We are a wholly-owned subsidiary of Pinnacle West. 4. See "Liquidity and Capital Resources" in Part I, Item 2 of this report for changes in capitalization for the nine months ended September 30, 2001. 5. Regulatory Accounting We are regulated by the ACC and FERC. The accompanying financial statements reflect the ratemaking policies of these commissions. For regulated operations, we prepare our financial statements in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 requires a cost-based, rate-regulated enterprise to reflect the impact of regulatory decisions in its financial statements. During 1997, the EITF of the FASB issued EITF 97-4. EITF 97-4 requires that SFAS No. 71 be discontinued no later than when legislation is passed or a rate order is issued that contains sufficient detail to determine its effect on the portion of the business being deregulated, which could result in write-downs or write-offs of physical and/or regulatory assets. Additionally, the EITF determined that regulatory assets should not be written off if they are to be recovered from a portion of the entity which continues to apply SFAS No. 71. The 1999 Settlement Agreement was approved by the ACC in September 1999 (see Note 6 for a discussion of the agreement). Consequently, we have discontinued the application of SFAS No. 71 for our generation operations. As a result, we tested the generation assets for impairment and determined that the generation assets were not impaired. Pursuant to the 1999 Settlement Agreement, a regulatory disallowance removed $234 million pretax ($183 million net present value) from ongoing regulatory cash flows and was recorded as a net reduction of regulatory assets. This reduction ($140 million after income taxes was reported as an extraordinary charge on the income statement during the third quarter of 1999. Prior to the 1999 Settlement Agreement, under the 1996 regulatory agreement (see Note 6), the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004. -9- The regulatory assets to be recovered under the 1999 Settlement Agreement are now being amortized through June 30, 2004 as follows (dollars in millions): 1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $86 $18 $686 The majority of our remaining regulatory assets relate to deferred income taxes and rate synchronization cost deferrals. The condensed balance sheets include the amounts listed below for generation assets not subject to SFAS No. 71 (for additional generation information see Note 8): (dollars in thousands)
September 30, December 31, 2001 2000 ----------- ----------- Electric plant in service and held for future use .......... $ 3,897,732 $ 3,856,600 Accumulated depreciation and amortization .................. (1,771,158) (1,693,079) Construction work in progress .............................. 97,537 86,329 Nuclear fuel, net of amortization .......................... 54,853 47,389
6. Regulatory Matters ELECTRIC INDUSTRY RESTRUCTURING STATE 1999 SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive Settlement Agreement with various parties, including representatives of major consumer groups, related to the implementation of retail electric competition. On September 23, 1999, the ACC voted to approve the 1999 Settlement Agreement, with some modifications. On December 13, 1999, two parties filed lawsuits challenging the ACC's approval of the 1999 Settlement Agreement. Each party bringing the lawsuits appealed the ACC's order approving the 1999 Settlement Agreement directly to the Arizona Court of Appeals, as provided by Arizona law. In one of the appeals, on December 26, 2000, the Arizona Court of Appeals affirmed the ACC's approval of the 1999 Settlement Agreement. This decision was not appealed and has become final. In the other appeal, on April 5, 2001, the Arizona Court of Appeals again affirmed the ACC's approval of the 1999 Settlement Agreement. The Arizona Consumers Council, which filed that appeal, petitioned the Arizona Supreme Court for review of the Court of Appeals' decision. On October 5, 2001, the Arizona Supreme Court agreed to hear the appeal on the singular issue of whether the ACC could itself become a party to the Settlement Agreement by virtue of its approval of the Settlement Agreement. The Supreme Court has not yet set a date for oral argument on this matter. The following are the major provisions of the 1999 Settlement Agreement, as approved: -10- * We have reduced, and will reduce, rates for standard offer service for customers with loads less than three MW in a series of annual retail electricity price reductions of 1.5% beginning July 1, 1999 through July 1, 2003, for a total of 7.5%. The first reduction of approximately $24 million ($14 million after income taxes) included the July 1, 1999 retail price decrease of approximately $11 million ($7 million after income taxes) related to the 1996 regulatory agreement. See "1996 Regulatory Agreement" below. Based on the price reductions authorized in the 1999 Settlement Agreement, there were also retail price decreases of approximately $28 million ($17 million after taxes), or 1.5%, effective July 1, 2000, and approximately $27 million ($16 million after taxes), or 1.5%, effective July 1, 2001. For customers having loads three MW or greater, standard offer rates will be reduced in varying annual increments that total 5% in the years 1999 through 2002. * Unbundled rates being charged by us for competitive direct access service (for example, distribution services) became effective upon approval of the 1999 Settlement Agreement, retroactive to July 1, 1999, and also became subject to annual reductions beginning January 1, 2000, that vary by rate class, through January 1, 2004. * There will be a moratorium on retail price changes for standard offer and unbundled competitive direct access services until July 1, 2004, except for the price reductions described above and certain other limited circumstances. Neither the ACC nor the Company will be prevented from seeking or authorizing rate changes prior to July 1, 2004 in the event of conditions or circumstances that constitute an emergency, such as an inability to finance on reasonable terms, or material changes in our cost of service for ACC-regulated services resulting from federal, tribal, state or local laws, regulatory requirements, judicial decisions, actions or orders. * We will be permitted to defer for later recovery prudent and reasonable costs of complying with the ACC electric competition rules, system benefits costs in excess of the levels included in then-current (1999) rates, and costs associated with the "provider of last resort" and standard offer obligations for service after July 1, 2004. These costs are to be recovered through an adjustment clause or clauses commencing on July 1, 2004. * Our distribution system opened for retail access effective September 24, 1999. Customers were eligible for retail access in accordance with the phase-in adopted by the ACC under the electric competition rules (see "Retail Electric Competition Rules" below), including an additional 140 MW being made available to eligible non-residential customers. We opened our distribution system to retail access for all customers on January 1, 2001. * Prior to the 1999 Settlement Agreement, we were recovering substantially all of our regulatory assets through July 1, 2004, pursuant to the 1996 regulatory agreement. In addition, the 1999 Settlement Agreement states that we have demonstrated that our allowable stranded costs, after mitigation and exclusive of regulatory assets, are at least $533 million net present value. We will not be allowed to recover $183 million net present value of the above amounts. The 1999 Settlement Agreement provides that we will have the -11- opportunity to recover $350 million net present value through a competitive transition charge that will remain in effect through December 31, 2004, at which time it will terminate. The costs subject to recovery under the adjustment clause described above will be decreased or increased by any over/under-recovery due to sales volume variances. * We will form, or cause to be formed, a separate corporate affiliate or affiliates and transfer to such affiliate(s) our generating assets and competitive services at book value as of the date of transfer, and will complete the transfer no later than December 31, 2002. Accordingly, we plan to complete the move of such assets and services to the parent company or to Pinnacle West Energy by the end of 2002, as required. We will be allowed to defer and later collect, beginning July 1, 2004, sixty-seven percent of our costs to accomplish the required transfer of generation assets to an affiliate. * When the 1999 Settlement Agreement approved by the ACC is no longer subject to judicial review, we will move to dismiss all of our litigation pending against the ACC as of the date we entered into the 1999 Settlement Agreement. To protect our rights, we have several lawsuits pending on ACC orders relating to stranded cost recovery and the adoption and amendment of the ACC's electric competition rules, which would be voluntarily dismissed at the appropriate time under this provision. As discussed in Note 5 above, we have discontinued the application of SFAS No. 71 for our generation operations. PROPOSED RULE VARIANCE AND PURCHASE POWER AGREEMENT. As authorized by the 1999 Settlement Agreement, we intend to move substantially all of our generation assets to Pinnacle West Energy no later than December 31, 2002. Commencing upon the transfer of the fossil-fueled generating assets and the receipt of certain regulatory approvals, Pinnacle West Energy expects to sell its power at wholesale to Pinnacle West's power marketing division, which, in turn, is expected to sell power to us and to non-affiliated power purchasers. In a filing with the ACC on October 18, 2001, we requested the ACC to (a) grant us a partial variance from an ACC rule that would obligate us to acquire all of our customers' standard offer generation requirements from the competitive market (with at least 50% of that coming from a "competitive bidding" process) starting in 2003 and (b) approve as just and reasonable a long-term purchase power agreement (PPA) between us and Pinnacle West. We have requested these ACC actions to ensure continued reliable service to our standard offer customers in a volatile generation market and to recognize Pinnacle West Energy's significant investment to serve our load. The following are the major provisions of the PPA: * The PPA would run through 2015, with three optional five-year renewal terms, which renewals would occur automatically unless notice is given by either us or Pinnacle West. * The PPA would provide for all of our anticipated standard offer generation needs, including any necessary reserves, except for (a) those provided by us through renewable resources or other generation assets retained by us; (b) amounts that we are obligated by law to -12- purchase from "qualified facilities" and other forms of distributed generation; and (c) any purchased power agreements that we cannot transfer to Pinnacle West Energy. * Pinnacle West would assume contractual responsibility for reliability and would supplement any potential shortfall even after full utilization of Pinnacle West Energy's dedicated generating resources. * Pinnacle West would supply our standard offer requirements through a combination of (a) our generation assets transferred to Pinnacle West Energy; (b) certain of Pinnacle West Energy's new Arizona generation projects to be constructed during the 2001-2004 period to reliably serve our load requirements; (c) power procured by Pinnacle West under certain "dedicated contracts"; and (d) power procured on the open market, including a competitively-bid component described below. * Beginning in 2003, Pinnacle West would acquire 270 MW of our standard offer requirements on the open market through a competitive bidding process. This competitive bid obligation would be increased by an additional 270 MW each year through 2008 (representing approximately 23% of estimated 2008 peak load). * Pinnacle West would charge us based on (a) a combination of fixed and variable price components for the Pinnacle West Energy assets, subject to periodic adjustment, and (b) a pass-through of Pinnacle West's costs to procure power from the remaining sources. * The PPA would take effect on the latest of the following events: (a) transfer of non-nuclear generating assets from us to Pinnacle West Energy; (b) ACC approval of the rule variance and the PPA; and (c) FERC acceptance of the PPA and the companion agreement between Pinnacle West and Pinnacle West Energy. PROVIDER OF LAST RESORT OBLIGATION. Although the Rules allow retail customers to have access to competitive providers of energy and energy services (see "Retail Electric Competition Rules" below), we are the "provider of last resort" for standard offer customers under rates that have been approved by the ACC. Energy prices in the western wholesale market vary and, during the course of the last year, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. We expect that the market may continue to be volatile. We believe that through a combination of hedging and our current generation portfolio, we will be able to adequately manage our exposure to the volatility of the power market. However, in the event of shortfalls due to unforeseen increases in load demand or generation outages, we may need to purchase additional supplemental power in the wholesale spot market. Unless we are able to obtain an adjustment of our rates under the emergency provisions of the 1999 Settlement Agreement, there can be no assurance that we would be able to fully recover the costs of this power. -13- RETAIL ELECTRIC COMPETITION RULES. On September 21, 1999, the ACC voted to approve rules that provide a framework for the introduction of retail electric competition in Arizona. Under the 1999 Settlement Agreement, the Rules are to be interpreted and applied, to the greatest extent possible, in a manner consistent with the 1999 Settlement Agreement. If the two cannot be reconciled, we must seek, and the other parties to the 1999 Settlement Agreement must support, a waiver of the Rules in favor of the 1999 Settlement Agreement. On December 8, 1999, we filed a lawsuit to protect our legal rights regarding the Rules. This lawsuit is pending, along with several other lawsuits on ACC orders relating to stranded cost recovery (including those described above involving us), the adoption or amendment of the Rules, and the certification of competitive electric service providers. On November 27, 2000, a Maricopa County, Arizona, Superior Court judge issued a final judgment holding that the Rules are unconstitutional and unlawful in their entirety due to failure to establish a fair value rate base for competitive electric service providers and because certain of the Rules were not submitted to the Arizona Attorney General for certification. The judgment also invalidates all ACC orders authorizing competitive electric service providers, including APS Energy Services, to operate in Arizona. We do not believe the ruling affects the 1999 Settlement Agreement. The 1999 Settlement Agreement was not at issue in the consolidated cases before the judge. Further, the ACC made findings related to the fair value of our property in the order approving the 1999 Settlement Agreement. The ACC and other parties aligned with the ACC have appealed the ruling to the Arizona Court of Appeals, as a result of which the Superior Court's ruling is automatically stayed pending further judicial review. In a similar appeal concerning the issuance of competitive telecommunications CC&N's, the Arizona Court of Appeals invalidated rates for competitive carriers due to the ACC's failure to establish a fair value rate base for such carriers. That case has been appealed to the Arizona Supreme Court, where a decision is pending. The Rules approved by the ACC include the following major provisions: * They apply to virtually all Arizona electric utilities regulated by the ACC, including us. * Effective January 1, 2001, retail access became available to all our retail electricity customers. * Electric service providers that get CC&N's from the ACC can supply only competitive services, including electric generation, but not electric transmission and distribution. * Affected utilities must file ACC tariffs that unbundle rates for non-competitive services. * The ACC shall allow a reasonable opportunity for recovery of unmitigated stranded costs. * Absent an ACC waiver, prior to January 1, 2001, each affected utility (except certain electric cooperatives) must transfer all competitive generation assets and services either to an unaffiliated party or to a separate corporate affiliate. Under the 1999 Settlement Agreement, we -14- received a waiver to allow transfer of our generation and other competitive assets and services to affiliates no later than December 31, 2002. We plan to complete the move of such assets by the end of 2002, as required. 1996 REGULATORY AGREEMENT. In April 1996, the ACC approved a regulatory agreement between the ACC Staff and us. Based on the price reduction formula authorized in the agreement, the ACC approved retail price decreases (approximate) as follows (dollars in millions): Annual Electric Percentage Revenue Decrease Decrease Effective Date ---------------- -------- -------------- $49 3.4% July 1, 1996 $18 1.2% July 1, 1997 $17 1.1% July 1, 1998 $11 0.7% July 1, 1999 (a) (a) Included in the first rate reduction under the 1999 Settlement Agreement (see above). The regulatory agreement also required that Pinnacle West infuse $200 million of common equity into us in annual payments of $50 million from 1996 through 1999. All of these equity infusions were made by December 31, 1999. LEGISLATION. In May 1998, a law was enacted to facilitate implementation of retail electric competition in Arizona. The law includes the following major provisions: * Arizona's largest government-operated electric utility (Salt River Project) and, at their option, smaller municipal electric systems must (i) make at least 20% of their 1995 retail peak demand available to electric service providers by December 31, 1998 and for all retail customers by December 31, 2000; (ii) decrease rates by at least 10% over a ten-year period beginning as early as January 1, 1991; (iii) implement procedures and public processes comparable to those already applicable to public service corporations for establishing the terms, conditions, and pricing of electric services as well as certain other decisions affecting retail electric competition; * describes the factors which form the basis of consideration by Salt River Project in determining stranded costs; and * metering and meter reading services must be provided on a competitive basis during the first two years of competition only for customers having demands in excess of one MW (and that are eligible for competitive generation services), and thereafter for all customers receiving competitive electric generation. GENERAL We cannot accurately predict the impact of full retail competition on our financial position, cash flows, results of operations, or liquidity. As competition in the electric industry continues to evolve, we will continue to -15- evaluate strategies and alternatives that will position us to compete in the new regulatory environment. FEDERAL The 1992 Energy Act and recent rulemakings by FERC have promoted increased competition in the wholesale energy markets. We do not expect these rules to have a material impact on our financial statements. In June 2001, FERC adopted a price mitigation plan that constrains the price of electricity in the wholesale spot electricity market in the western United States. The plan remains in effect until September 30, 2002. The Company cannot accurately predict the overall financial impact of the plan on the various aspects of its business, including its wholesale and purchased power activities. 7. Nuclear Insurance The Palo Verde participants have insurance for public liability payments resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the accumulated funds, we could be assessed retrospective premium adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per incident. Based upon our 29.1% interest in the three Palo Verde units, our maximum potential assessment per incident is approximately $77 million, with an annual payment limitation of approximately $9 million. The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. 8. Business Segments We have two principal business segments (determined by products, services and regulatory environment), which consist of activities related to the transmission and distribution of electricity (delivery business segment) and the generation of electricity and wholesale and power trading (generation business segment). These reportable segments reflect a change in the reporting of our functional activities. Before January 1, 2001, our reported segment information combined transmission and distribution activities with wholesale and power trading activities. Our current operational activities are more closely based on the strong integration of our wholesale and power trading activities with our generation of electricity, and have been combined for segment reporting purposes. The corresponding information for earlier periods has been restated. -16- Beginning in 2001, we changed our method of allocating revenues between the delivery business segment and the generation business segment to reflect the seasonal impact of market prices. This change had the impact of decreasing delivery segment income and increasing generation segment income in all the periods presented when compared to the prior comparable periods. The after-tax change is $45 million in the three-month period and $2 million in the nine- and twelve-month periods. Eliminations primarily relate to intersegment sales of electricity. Segment information for the three, nine and twelve months ended September 30, 2001 and 2000 is as follows (dollars in millions):
3 Months Ended 9 Months Ended 12 Months Ended September 30, September 30, September 30, ------------------ ------------------ ------------------ 2001 2000 2001 2000 2001 2000 ------- ------- ------- ------- ------- ------- Operating Revenues: Delivery $ 612 $ 683 $ 1,577 $ 1,563 $ 1,984 $ 1,963 Generation 805 1,194 2,086 1,886 2,609 2,169 Eliminations (368) (311) (788) (718) (969) (901) ------- ------- ------- ------- ------- ------- Total $ 1,049 $ 1,566 $ 2,875 $ 2,731 $ 3,624 $ 3,231 ======= ======= ======= ======= ======= ======= Income Before Accounting Change: Delivery $ 6 $ 28 $ 95 $ 84 $ 116 $ 115 Generation 102 96 147 169 180 173 ------- ------- ------- ------- ------- ------- Total $ 108 $ 124 $ 242 $ 253 $ 296 $ 288 ======= ======= ======= ======= ======= =======
As of September 30, As of December 31, 2001 2000 ---- ---- Assets: Delivery $3,950 $3,987 Generation 2,670 2,413 ------ ------ Total $6,620 $6,400 ====== ====== 9. Accounting Matters In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This Statement addresses financial accounting and reporting for acquired goodwill and other intangible assets and supersedes APB Opinion No. 17, "Intangible Assets." We are currently evaluating the impacts of the new standard and do not expect it to have a material impact on our financial statements. We have no goodwill. This standard is effective for the year beginning January 1, 2002. In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." The standard requires the estimated present value of the cost of decommissioning and certain other removal costs to be recorded as a liability, along with an offsetting plant asset when a decommissioning or other removal obligation is incurred. We are currently evaluating the impacts of the new standard, which is effective for the year beginning January 1, 2003. -17- In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." This statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and the accounting and reporting provisions for the disposal of a segment of a business. SFAS No. 144 is effective for the year beginning January 1, 2002. We are currently evaluating the impacts of the new standard and do not expect it to have a material impact on our financial statements. 10. Derivative Instruments We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal and emissions allowances. We employ established procedures to manage risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into derivative transactions to hedge purchases and sales of electricity, fuels, and emissions allowances/credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. In addition, subject to specified risk parameters we engage in trading activities intended to profit from market price movements. Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheet and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are either recognized periodically in income or shareholder's equity (as a component of other comprehensive income), depending on whether or not the derivative meets specific hedge accounting criteria. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness is recognized immediately in net income. This new standard may result in additional volatility in our net income and comprehensive income. In June 2001, the FASB determined that certain electricity contracts, including those with option characteristics and those subject to "bookout," would qualify for the normal purchases and sales exception if certain criteria were met. Prior to the issuance of the guidance, we accounted for electricity contracts with characteristics of options and those subject to "bookout" as normal purchases and sales. As a result, we did not previously mark these contracts to their fair market values each reporting period. The effective date of this new guidance was July 1, 2001. As a result of adopting SFAS No. 133, we recognized $118 million of derivative assets and $16 million of derivative liabilities in our balance sheet as of January 1, 2001. Also as of January 1, 2001, we recorded a $3 million after-tax loss in net income as a cumulative effect of a change in accounting principle and a $65 million after-tax gain in equity (as a component of other comprehensive income). The gain resulted from unrealized gains on cash flow hedges. As of July 1, 2001, we recorded an additional $12 million after-tax loss in net income and an additional $8 million after-tax gain in equity (as a component of other comprehensive income), as a result of adopting the new guidance related to electricity contracts. These adjustments resulted primarily from contracts -18- with characteristics of options that did not meet the new criteria for the normal purchases and sales exception. The impact of the new guidance is reflected as a cumulative effect of a change in accounting principle. In October 2001, FASB again revised its guidance for option-like contracts. We are currently in the process of evaluating the effect, if any, of this revised guidance. The change in derivative fair value in the condensed statements of income for the three, nine and twelve months ending September 30, 2001 and 2000 is comprised of the following (dollars in thousands):
Nine Months Three Months Ended Ended Twelve Months Ended September 30, September 30, September 30, -------------------- -------------------- -------------------- 2001 2000 2001 2000 2001 2000 -------- -------- -------- -------- -------- -------- Ineffective portion of derivatives qualifying for hedge accounting (a) $ (1,879) $ -- $ (8,063) $ -- $ (8,063) $ -- Discontinuance of cash flow hedges for forecasted transactions that will not occur (1,367) -- (9,692) -- (9,692) -- Reclassification of mark-to-market to realized 19,880 -- 26,359 -- 26,359 -- -------- -------- -------- -------- -------- -------- Total $ 16,634 $ -- $ 8,604 $ -- $ 8,604 $ -- ======== ======== ======== ======== ======== ========
(a) Time value component of options excluded from assessment of hedge effectiveness. As of September 30, 2001, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is thirty-nine months. During the twelve months ending September 30, 2002, we estimate that a net loss of $23 million before income taxes will be reclassified from accumulated other comprehensive income as an offset to the effect on earnings of market price changes for the related hedged transaction. Net gains and losses on derivatives utilized for trading activities are recognized in power marketing revenues on a current basis (the mark-to-market method). Trading positions are measured at fair value as of the balance sheet date. The mark-to-market gains recognized in power marketing revenues were the following for the three, nine and twelve months ended September 30, 2001 and 2000 (dollars in millions): -19- Three Months Nine Months Twelve Months Ended Ended Ended September 30, September 30, September 30, ------------- ------------- ------------- 2001 2000 2001 2000 2001 2000 ---- ---- ----- ---- ----- ---- Mark-to-market gains (losses) $ 40 $(45) $ 135 $(18) $ 162 $(17) Realized gains (losses) (26) 66 (25) 80 (56) 83 ---- ---- ----- ---- ----- ---- Total trading gains $ 14 $ 21 $ 110 $ 62 $ 106 $ 66 ==== ==== ===== ==== ===== ==== 11. Comprehensive Income Components of comprehensive income for the three, nine and twelve months ended September 30, 2001 and 2000, are as follows (dollars in thousands):
Three Months Nine Months Twelve Months Ended Ended Ended September 30, September 30, September 30, -------------------- --------------------- --------------------- 2001 2000 2001 2000 2001 2000 -------- -------- --------- -------- --------- -------- Net income $ 95,110 $124,231 $ 226,600 $252,857 $ 280,337 $288,335 -------- -------- --------- -------- --------- -------- Other comprehensive income(loss), net of tax: Cumulative effect of change in accounting for derivatives 7,801 -- 72,501 -- 72,501 -- Unrealized holding losses arising during period (11,353) -- (109,281) -- (109,281) -- Reclassification adjustment for derivatives (11,145) -- (29,829) -- (29,829) -- -------- -------- --------- -------- --------- -------- Total other comprehensive loss (14,697) -- (66,609) -- (66,609) -- -------- -------- --------- -------- --------- -------- Comprehensive income $ 80,413 $124,231 $ 159,991 $252,857 $ 213,728 $288,335 ======== ======== ========= ======== ========= ========
12. California Energy Market Issues and Refunds in the Pacific Northwest We are closely monitoring developments in the California energy market and the potential impact of those developments on us. We have evaluated, among other things, SCE's role as a Palo Verde and Four Corners participant; our transactions with the PX and the ISO; contractual relationships with SCE and PG&E; and power marketing exposures. Based on our current evaluations, we do not believe the foregoing matters will have a material adverse effect on our financial position and liquidity. We cannot predict with certainty, however, the impact that any future resolution, or attempted resolution, of the California energy market situation may have on us or the regional energy market in general. In July 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California during a specified time frame. This order calls for a hearing, with findings of fact due to FERC after the California ISO provides necessary historical data. FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The Administrative Law Judge at FERC in charge of that evidentiary proceeding made an initial finding that no refunds were appropriate. The Pacific Northwest issues will now be addressed by FERC Commissioners. Although FERC has -20- not yet made a final ruling in the Pacific Northwest matter or calculated the specific refund amounts due in California, we do not expect that the resolution of these issues will have a material adverse impact on our financial position, results of operations or liquidity. 13. Power Service Agreement By letter dated March 7, 2001, Citizens advised us that it believes we have overcharged Citizens by over $50 million under a power service agreement. We believe that our charges under the agreement were fully in accordance with the terms of the agreement. The Company and Citizens terminated the power service agreement effective July 15, 2001. In replacement of the power service agreement, Pinnacle West and Citizens entered into a power sale agreement under which Pinnacle West will supply Citizens with specified amounts of electricity and ancillary services through May 31, 2008. This new agreement does not address issues previously raised by Citizens with respect to charges under the original power service agreement through June 1, 2001. 14. 2001 Generation Summer Reliability Program We recently added over 200 MW of generating capability to enhance reliability for the summer of 2001 in light of market conditions in the western United States. We restored approximately 100 MW of previously mothballed gas-fired steam units at the West Phoenix Power Plant and refurbished the entire fossil plant fleet during the spring of 2001 (which resulted in additional capability of approximately 110 MW). Additionally, Pinnacle West Energy added over 300 MW of generating capacity (including 200 MW from leased portable generators) for the summer of 2001. -21- ARIZONA PUBLIC SERVICE COMPANY ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. INTRODUCTION In this section, we explain our results of operations, general financial condition, and outlook including: * the changes in our earnings for the three, nine and twelve months ended September 30, 2001 and 2000; * the effects of regulatory agreements on our results and outlook; * our capital needs and resources; * major factors that affect our financial outlook; and * our management of market risks. We are Arizona's largest electric utility and provide retail and wholesale electric service to the entire state with the exception of Tucson and about one-half of the Phoenix area. We also generate and, directly or through Pinnacle West's power marketing division, sell and deliver electricity to wholesale customers in the western United States. Pinnacle West owns all of our outstanding stock. OPERATING RESULTS The following table summarizes our revenues and earnings for the three, nine and twelve months ended September 30, 2001 and the comparable prior year periods: Periods ended September 30, (Unaudited) (dollars in millions) Three Months Nine Months Twelve Months Ended Ended Ended September 30, September 30, September 30, ----------------- ----------------- ----------------- 2001 2000 2001 2000 2001 2000 ------ ------ ------ ------ ------ ------ Operating Revenues $1,049 $1,566 $2,875 $2,731 $3,624 $3,231 Net Income $ 95(1) $ 124 $ 227(2) $ 253 $ 280(2) $ 288 (1) The three-month period ended September 30, 2001 includes an after-tax loss related to the cumulative effect of a change in accounting for derivatives of $12 million. (2) These periods include an after-tax loss related to the cumulative effect of a change in accounting for derivatives of $15 million. -22- Operating Results - Three-month period ended September 30, 2001 compared with three-month period ended September 30, 2000 Net income for the three months ended September 30, 2001 was $95 million compared with $124 million for the same period in the prior year. In July 2001, we recognized a $12 million after-tax loss in net income as a cumulative effect of a change in accounting for derivatives as required by SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". See Note 10 for further discussion. Income before accounting change for the three months ended September 30, 2001 was $108 million compared with $124 million for the same period in the prior year. The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
Increase/(Decrease) ------------------- Decreased margin on power marketing, trading and other wholesale activities $(35) Higher margin from retail sales 5 Retail price reductions (9) Higher replacement power costs on plant outages (6) SFAS No. 133 accounting adjustment 17 ---- Decrease in revenues, net of purchased power and fuel expense (28) Higher operations and maintenance expense primarily related to generation reliability and other costs (10) Miscellaneous items, net 11 ---- Net decrease in income before income taxes (27) Lower income taxes primarily due to lower income 11 ---- Net decrease in income before accounting change $(16) ====
Electric operating revenues decreased approximately $517 million primarily because of: * decreased power marketing revenues related to trading and wholesale activities primarily because of increased power marketing at Pinnacle West ($522 million); * increased retail revenues primarily related to higher sales volumes due to weather impacts and customer growth, partially offset by lower average usage per customer ($14 million); and * decreased retail revenues related to the reduction in retail electricity prices ($9 million). See Note 6 for information on the price reductions. Purchased power and fuel expenses decreased approximately $489 million primarily because of: * decreased power marketing costs related to trading and wholesale activities primarily because of increased power marketing at Pinnacle West ($487 million); * decreased costs for a SFAS No. 133 adjustment related to changes in electricity and gas market prices ($17 million). See Note 10 for additional information on SFAS No. 133; -23- * increased costs related to higher retail sales volumes and associated higher purchased power and fuel prices ($9 million); and * higher replacement power costs primarily for increased plant outages ($6 million). The increase in operations and maintenance expenses of $10 million primarily related to the generation reliability and power plant maintenance costs ($6 million) and other costs ($4 million). See Note 14 for additional information on the generation summer reliability program. Depreciation and amortization decreased $7 million primarily because of lower regulatory asset amortization. Interest expense decreased by $6 million primarily because of lower interest rates. Operating Results - Nine-month period ended September 30, 2001 compared with nine-month period ended September 30, 2000 Net income for the nine months ended September 30, 2001 was $227 million compared with $253 million for the same period in the prior year. In 2001, we recognized a $15 million after-tax loss in net income as a cumulative effect of a change in accounting for derivatives, as required by SFAS No. 133. See Note 10 for further discussion. Income before accounting change for the nine months ended September 30, 2001 was $242 million compared with $253 million for the same period in the prior year. The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
Increase/(Decrease) ------------------- Increased margin on generation sales other than Native Load $ 118 Decreased margin on power marketing, trading and other wholesale activities (8) Lower margin from retail sales (10) Retail price reductions (22) SFAS No. 133 accounting adjustments 9 Higher replacement power costs for plant outages (94) ----- Decrease in revenues, net of purchased power and fuel expense (7) Higher operations and maintenance expenses primarily related to generation reliability and other costs (33) Miscellaneous items, net 23 ----- Net decrease in income before income taxes (17) Lower income taxes primarily due to lower income 6 ----- Net decrease in income before accounting change $ (11) =====
Electric operating revenues increased approximately $144 million primarily because of: * increased wholesale revenues primarily related to generation sales other than for Native Load ($182 million); -24- * decreased power marketing revenues related to trading and other wholesale activities ($74 million); * increased retail revenues primarily related to higher sales volumes due to weather impacts and customer growth, partially offset by lower average usage per customer ($58 million); and * decreased retail revenues related to reductions in retail electricity prices ($22 million). See Note 6 for information on the price reductions. Purchased power and fuel expenses increased approximately $151 million primarily because of: * increased costs related to generation other than Native Load ($64 million); * decreased power marketing costs related to trading and other wholesale activities ($66 million); * higher replacement power costs primarily for increased plant outages ($94 million), including costs of $12 million related to the Palo Verde outage extension to replace fuel control element assemblies; * increased costs related to higher retail sales volumes and associated higher purchased power and fuel prices ($68 million); and * decreased costs related to SFAS No. 133 adjustments related to changes in electricity and gas market prices ($9 million). See Note 10 for additional information on SFAS No. 133. The increase in operations and maintenance expenses of $33 million primarily related to generation reliability and increased power plant maintenance ($27 million) and increased pension and other costs ($6 million). Depreciation and amortization decreased $8 million primarily because of lower regulatory asset amortization. Other net income increased $6 million primarily because of insurance recovery of environmental remediation costs. Interest expense decreased by $13 million primarily because of lower interest rates and increased capitalized interest resulting from higher construction project balances. OPERATING RESULTS - TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2001 COMPARED WITH TWELVE-MONTH PERIOD ENDED SEPTEMBER 30, 2000 Net income for the twelve months ended September 30, 2001 was $280 million compared with $288 million for the same period in the prior year. In 2001, we recognized a $15 million after-tax loss in net income as a cumulative effect of a change in accounting for derivatives, as required by SFAS No.133. See Note 10 for further discussion. Income before accounting change for the twelve months ended September 30, 2001 was $296 million compared with $288 million for the same period in the prior year. The major factors that increased (decreased) income before accounting change were as follows (dollars in millions): -25-
Increase/(Decrease) ------------------- Increased margin on generation sales other than Native Load $ 163 Decreased margin on power marketing, trading and other wholesale activities (3) Retail price reductions (27) Lower margin from retail sales (13) SFAS No. 133 accounting adjustments 9 Higher replacement power costs for plant outages (116) ----- Increase in revenues, net of purchased power and fuel expense 13 Higher operations and maintenance expense primarily related to generation reliability and other costs (16) Miscellaneous items, net 26 ----- Net increase in income before income taxes 23 Higher income taxes primarily due to higher income (15) ----- Net increase in income before accounting change $ 8 =====
Electric operating revenues increased approximately $393 million because of: * increased wholesale revenues primarily related to generation sales other than for Native Load ($269 million); * increased power marketing revenues related to trading and other wholesale activities ($84 million); * increased retail revenues primarily related to higher sales volumes due to weather impacts and customer growth, partially offset by lower average usage per customer ($67 million); and * decreased retail revenues related to the reduction in retail electricity prices ($27 million). See Note 6 for information on the price reductions. Purchased power and fuel expenses increased approximately $380 million primarily because of: * increased costs related to generation other than Native Load ($106 million); * increased power marketing costs related to trading and other wholesale activities ($87 million); * higher replacement power costs primarily for increased plant outages ($116 million), including costs of $12 million related to the Palo Verde outage extension to replace fuel control element assemblies; * higher costs related to retail sales volumes and associated purchased power and fuel prices ($80 million); and * decreased costs for SFAS No. 133 adjustments related to changes in electricity and gas market prices ($9 million). See Note 10 for additional information on SFAS No. 133. The increase in operations and maintenance expenses of $16 million primarily related to generation summer reliability programs and increased power plant maintenance, partially offset by approximately $12 million of non-recurring items recorded in the fourth quarter of 1999. See Note 14 for information on the generation summer reliability program. See Note 12 for additional information related to the California energy situation. -26- Other net income increased $7 million primarily because of insurance recovery of environmental remediation costs. Interest expense decreased by $16 million primarily because of increased capitalized interest resulting from higher construction project balances and lower interest rates. LIQUIDITY AND CAPITAL RESOURCES For the nine months ended September 30, 2001, we incurred approximately $340 million in capital expenditures, which is approximately 74% of the most recently estimated 2001 capital expenditures. Our projected capital expenditures for the next three years are $461 million in 2001; $487 million in 2002; and $305 million in 2003. Our long-term debt redemption requirements, including optional repayments on long-term debt are: $384 million in 2001; $125 million in 2002; and zero in 2003. During 2001, we expect to satisfy our long-term debt redemption requirements with cash from operations and long and short-term borrowings. Through September 2001, we redeemed $62 million of our long-term debt. We have also deposited $72 million, plus interest, with the trustee for the redemption in December 2001 of our First Mortgage Bonds, 9% Series due 2021. On October 5, 2001, we issued $400 million of our 6.375% Notes due 2011. Based on market conditions and optional call provisions, we may make optional redemptions of long-term debt from time to time. Although provisions in our first mortgage bond indenture, articles of incorporation, and ACC financing orders establish maximum amounts of additional first mortgage bonds and preferred stock that we may issue, we do not expect any of these provisions to limit our ability to meet our capital requirements. BUSINESS OUTLOOK This section describes several major factors affecting our financial outlook. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING See "Business Outlook - Competition and Industry Restructuring" in Item 7 of the 2000 10-K and Note 6 above for a discussion of developments affecting retail and wholesale electric competition. See Note 5 for a discussion of regulatory accounting. CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST See Note 12 for information regarding California energy market issues and possible Pacific Northwest refunds. FACTORS AFFECTING OPERATING REVENUES Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona and in competitive retail and wholesale bulk power markets in the western United States. -27- These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer, as well as electricity prices and variations in weather from period to period. In our regulated retail market area, we will provide electricity services to standard-offer, full-service customers and to energy delivery customers who have chosen another provider for their electricity commodity needs (unbundled customers). Customer growth in our service territory averaged 4.1% a year for the three years 1998 through 2000; we currently expect customer growth to average 3% to 4% a year for 2001 through 2003. We currently estimate that retail electricity sales in kilowatt-hours will grow 3% to 4.5% a year in 2001 through 2003, before the retail effects of weather variations. The customer growth and sales growth referred to in this paragraph apply to energy delivery customers. As industry restructuring evolves in the regulated market area, we cannot predict the number of our standard offer customers that will switch to unbundled service. Wholesale activities will be affected by electricity prices and costs of available fuel and purchased power in the western United States, as well as competitive market conditions and regulatory and legislative changes in various state and federal jurisdictions, including the price mitigation plan adopted by FERC in June 2001 (see Note 6). These factors have significantly affected our trading and wholesale power activities and their resultant earnings contributions over the last several years. We cannot predict future contributions from trading and wholesale activities. See Note 10 and Item 3 below for additional information. OTHER FACTORS AFFECTING FUTURE FINANCIAL RESULTS Purchased power and fuel costs are impacted by our electricity sales volumes, existing contracts for generation fuel and purchased power, our power plant performance, prevailing market prices, and our hedging program for managing such costs. See "Natural Gas Supply" in Part II for additional information on gas transportation costs. Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant operations, inflation, and other factors. Depreciation and amortization expenses are expected to be affected by net additions to existing utility plant and other property and changes in regulatory asset amortization. See Note 5 for the regulatory asset amortization that is being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement. Taxes other than income taxes consist primarily of property taxes, which are affected by tax rates and the value of property in service and under construction. We expect property taxes to increase primarily due to our additions to existing facilities. Interest costs are affected by the amount of debt outstanding and the interest rates on that debt. We cannot accurately predict the impact of full retail competition on our financial position, cash flows, results of operations, or liquidity. As competition in the electric industry continues to evolve, we will continue to -28- evaluate strategies and alternatives that will position us to compete effectively in a restructured industry. Our financial results may be affected by the application of SFAS No. 133. See Note 10 for further information. Our financial results may be affected by a number of broad factors. See "Forward-Looking Statements" below for further information on such factors, which may cause our actual future results to differ from those we currently seek or anticipate. RATE MATTERS See Note 6 for a discussion of a price reduction effective as of July 1, 2001, and for a discussion of the 1999 Settlement Agreement that will, among other things, result in five annual price reductions over a four-year period ending July 1, 2003. FORWARD-LOOKING STATEMENTS This document contains forward-looking statements based on current expectations and we assume no obligation to update these statements. Because actual results may differ materially from expectations, we caution readers not to place undue reliance on these statements. A number of factors could cause future results to differ materially from historical results, or from results or outcomes currently expected or sought by us. These factors include the ongoing restructuring of the electric industry; the outcome of regulatory and legislative proceedings relating to the restructuring; state and federal regulatory and legislative decisions and actions, including the price mitigation plan adopted by FERC in June 2001; regional economic and market conditions, including the California energy situation, which could affect customer growth and the cost of power supplies; the cost of debt and equity capital; weather variations affecting local and regional customer energy usage; conservation programs; power plant performance; our ability to compete successfully outside traditional regulated markets (including the wholesale market); and technological developments in the electric industry. These factors and the other matters discussed above may cause future results to differ materially from historical results, or from results or outcomes we currently expect or seek. ITEM 3. MARKET RISKS Our operations include managing market risks related to changes in commodity prices, interest rates, and investments held by our nuclear decommissioning trust fund. We are exposed to the impact of market fluctuations in the price and transportation costs of electricity, natural gas, coal, and emissions allowances. We employ established procedures to manage our risks associated with these market fluctuations by utilizing various commodity derivatives, including exchange-traded futures and options and over-the-counter forwards, options, and swaps. As part of our overall risk management program, we enter into these derivative transactions to ensure that we have enough energy for our customers and limit our exposure to volatile wholesale prices for power and fuel. In -29- addition, we engage in trading activities intended to profit from favorable movements of market prices. As of September 30, 2001, a hypothetical adverse price movement of 10% in the market price of our commodity derivative portfolio would decrease the fair market value of these contracts by approximately $20 million. This analysis does not include the favorable impact this same hypothetical price move would have on the underlying physical exposures being hedged with the commodity derivative portfolio. We plan to complete the move of our wholesale power marketing and trading activities to the parent company by the end of 2002. We are exposed to credit losses in the event of non-performance or non-payment by counterparties. We use a credit management process to assess and monitor the financial exposure of counterparties. Despite the fact that the great majority of our trading counterparties are rated as investment grade by the credit rating agencies, there is still a possibility that one or more of these companies could default, resulting in a material impact on earnings for a given period. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund. Our policy is to manage interest rates through the use of a combination of fixed-rate and floating-rate debt. The nuclear decommissioning fund also has risks associated with changing market values of equity investments. Nuclear decommissioning costs are recovered in regulated electricity prices. -30- PART II - OTHER INFORMATION ITEM 5. OTHER INFORMATION CONSTRUCTION AND FINANCING PROGRAMS See "Liquidity and Capital Resources" in Part I, Item 2 of this report for a discussion of our construction and financing programs. COMPETITION AND ELECTRIC INDUSTRY RESTRUCTURING RETAIL. See Note 6 of Notes to Condensed Financial Statements in Part I, Item 1 of this report for a discussion of competition and the rules regarding the introduction of retail electric competition in Arizona and a settlement agreement with the ACC. WHOLESALE. On October 16, 2001, the Company and other owners of electric transmission lines in the Southwest filed with FERC a request for a declaratory order confirming that their proposal to form WestConnect would satisfy FERC's requirements for the formation of a regional transmission organization. The Company and the other filing parties have agreed to fund the start-up of WestConnect's operations, which are projected to begin in 2004, subject to FERC approval. WestConnect has been structured as a for-profit RTO and evolved from DesertSTAR, a non-profit corporation in which we participated, which was originally designed to serve as an RTO for the southwestern United States. ENVIRONMENTAL MATTERS The Arizona Department of Environmental Quality issued to us Notices of Violation, dated September 25, 2001 and October 15, 2001 alleging, among other things, burning of unauthorized materials and storage of hazardous waste without a permit. Each Notice of Violation requires us to achieve and document compliance with specific environmental requirements. Although ADEQ may still seek civil penalties or take other enforcement action against us, we do not expect these matters to have a material adverse effect on our financial position, results of operations, or liquidity. NATURAL GAS SUPPLY The gas supply for the Company and Pinnacle West Energy gas-fired facilities located, and to be located, in Pinal, Maricopa and Yuma Counties in Arizona, is transported pursuant to a firm, Full Requirements Transportation Service Agreement with El Paso Natural Gas Company. The transportation agreement features a 10 year rate moratorium established in a comprehensive rate case settlement entered into in 1996. In a pending FERC proceeding, El Paso has proposed allocating its gas pipeline capacity in such a way that our (and other companies' with the same contract type) gas transportation rights could be significantly impacted. Various parties, including us and Pinnacle West Energy, have challenged this allocation as being inconsistent with El Paso's existing contractual obligations and the 1996 settlement. At this time, there are ongoing discussions among FERC, El Paso and other affected parties to resolve these issues. We cannot currently predict the outcome of this matter. -31- ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits Exhibit No. Description ----------- ----------- 4.1 Fifth Supplemental Indenture, dated as of October 1, 2001, to Indenture, dated as of January 15, 1998, between the Company and The Chase Manhattan Bank 12.1 Ratio of Earnings to Fixed Charges In addition, the Company hereby incorporates the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation ss.229.10(d) by reference to the filings set forth below:
ORIGINALLY FILED DATE EXHIBIT NO. DESCRIPTION AS EXHIBIT: FILE NO.(1) EFFECTIVE ----------- ----------- ----------- ----------- --------- 3.1 Articles of Incorporation 4.2 to Form S-3 1-4473 9-29-93 restated as of May 25, Registration Nos. 1988 33910 and 33--55248 by means of September 24, 1993 Form 8-K Report 3.2 Bylaws, amended as of 3.1 to 1995 Form 10-K 1-4473 1-20-00 February 20, 1996 Report
(b) Reports on Form 8-K During the quarter ended September 30, 2001, and the period from October 1 through November 5, 2001, we filed the following reports on Form 8-K: Report dated October 18, 2001 regarding (i) the Arizona Supreme Court's decision to review a lower court decision affirming the 1999 Settlement Agreement; and (ii) the Company's October 18, 2001 filing with the ACC requesting ACC approval of a rule variance and a purchase power agreement with the Company. Report dated October 2, 2001 comprised of Exhibits to the Company's Registration Statements (Registration Nos. 333-58445 and 333-94277) relating to the Company's offering of $400 million of Notes. ---------- (1) Reports filed under File No. 1-4473 were filed in the office of the Securities and Exchange Commission located in Washington, D.C. -32- SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated: November 5, 2001 By: Michael V. Palmeri ------------------------------------ Michael V. Palmeri Vice President, Finance (Principal Accounting Officer and Officer Duly Authorized to sign this Report) EX-4.1 3 ex4-1.txt FIFTH SUPPLEMENTAL INDENTURE DATED 10-1-01 Exhibit 4.1 --------------------------------------------- ARIZONA PUBLIC SERVICE COMPANY TO THE CHASE MANHATTAN BANK TRUSTEE Fifth Supplemental Indenture Dated as of October 1, 2001 To Indenture Dated as of January 15, 1998 6.375% Notes Due 2011 --------------------------------------------- FIFTH SUPPLEMENTAL INDENTURE, dated as of October 1, 2001, between Arizona Public Service Company, a corporation duly organized and existing under the laws of the State of Arizona (herein called the "Company"), having its principal office at 400 North Fifth Street, Phoenix, Arizona 85004, and The Chase Manhattan Bank, a New York banking corporation, as Trustee (herein called the "Trustee") under the Indenture dated as of January 15, 1998 between the Company and the Trustee (the "Indenture"). RECITALS OF THE COMPANY The Company has executed and delivered the Indenture to the Trustee to provide for the issuance from time to time of its unsecured debentures, notes or other evidences of indebtedness (the "Securities"), said Securities to be issued in one or more series as provided in the Indenture. Pursuant to the terms of the Indenture, the Company desires to provide for the establishment of a new series of its Securities to be known as its 6.375% Notes Due 2011 (herein called the "Notes Due 2011"), the form and substance of such Notes Due 2011 and the terms, provisions, and conditions thereof to be set forth as provided in the Indenture and this Fifth Supplemental Indenture. All things necessary to make this Fifth Supplemental Indenture a valid agreement of the Company, and to make the Notes Due 2011, when executed by the Company and authenticated and delivered by the Trustee, the valid obligations of the Company, have been done. NOW, THEREFORE, THIS FIFTH SUPPLEMENTAL INDENTURE WITNESSETH: For and in consideration of the premises and the purchase of the Notes Due 2011 by the Holders thereof, and for the purpose of setting forth, as provided in the Indenture, the form and substance of the Notes Due 2011 and the terms, provisions, and conditions thereof, it is mutually agreed, for the equal and proportionate benefit of all Holders of the Notes Due 2011, as follows: ARTICLE ONE GENERAL TERMS AND CONDITIONS OF THE NOTES DUE 2011 SECTION 101. There shall be and is hereby authorized a series of Securities designated the "6.375% Notes Due 2011" initially limited in aggregate principal amount to $400,000,000, which amount shall be as set forth in any Company Order for the authentication and delivery of Notes Due 2011. The Notes Due 2011 shall mature and the principal shall be due and payable together with all accrued and unpaid interest thereon on October 15, 2011, and shall be issued in the form of registered Notes Due 2011 without coupons. The foregoing principal amount of the Notes Due 2011 may be increased from time to time as permitted by Section 301 of the Indenture. All Notes Due 2011 need not be issued at the same time and such series may be reopened at any time, without notice to, or the consent of, the then 2 existing Holders, for issuances of additional Notes Due 2011. Any such additional Notes Due 2011 will be equal in rank and have the same maturity, payment terms, redemption features, and other terms, except for the payment of interest accruing prior to the issue date of the further Notes Due 2011 and for the first payment of interest following the issue date of the further Notes Due 2011, as those initially issued. SECTION 102. The Notes Due 2011 shall be issued in certificated form, except that the Notes Due 2011 shall be issued initially as a Global Security to and registered in the name of Cede & Co., as nominee of The Depository Trust Company, as Depositary therefor. Any Notes Due 2011 to be issued or transferred to, or to be held by, Cede & Co. (or any successor thereof) for such purpose shall bear the depositary legend in substantially the form set forth at the top of the form of Note Due 2011 in Article Two hereof (in lieu of that set forth in Section 204 of the Indenture), unless otherwise agreed by the Company, such agreement to be confirmed in writing to the Trustee. Such Global Security may be exchanged in whole or in part for Notes Due 2011 registered, and any transfer of such Global Security in whole or in part may be registered, in the name or names of Persons other than such Depositary or a nominee thereof only under the circumstances set forth in Clause (2) of the last paragraph of Section 305 of the Indenture, or such other circumstances in addition to or in lieu of those set forth in Clause (2) of the last paragraph of Section 305 of the Indenture as to which the Company shall agree, such agreement to be confirmed in writing to the Trustee. Principal of, and premium, if any, and interest on the Notes Due 2011 will be payable, the transfer of Notes Due 2011 will be registrable and Notes Due 2011 will be exchangeable for Notes Due 2011 bearing identical terms and provisions, at the office or agency of the Company in the Borough of Manhattan, The City and State of New York; PROVIDED, HOWEVER, that payment of interest may be made at the option of the Company by check mailed to the registered holder at such address as shall appear in the Security Register. SECTION 103. Each Note Due 2011 will bear interest at the rate of 6.375% from October 5, 2001 or from the most recent Interest Payment Date (as hereinafter defined) to which interest has been paid or duly provided for until the principal thereof is paid or made available for payment, payable on April 15 and October 15 of each year (each, an "Interest Payment Date"), commencing on April 15, 2002, to the person in whose name such Note Due 2011 or any Predecessor Security is registered, at the close of business on April 1 or October 1, as the case may be, whether or not a Business Day, immediately preceding the Interest Payment Date. Any such interest installment not punctually paid or duly provided for shall forthwith cease to be payable to the registered holders on such regular record date, and may be paid to the person in whose name the Note Due 2011 (or one or more Predecessor Securities) is registered at the close of business on a special record date to be fixed by the Trustee for the payment of such defaulted interest, notice whereof shall be given to the registered holders of the Notes Due 2011 not less than 10 days prior to such special record date, or may be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange on which the Notes Due 2011 may be listed, and upon such notice as may be required by such exchange, all as more fully provided in the Indenture. The amount of interest payable for any period will be computed on the basis of a 360-day year of twelve 30-day months. Interest will accrue from October 5, 2001 to, but not including, the 3 relevant payment date. In the event that any date on which interest is payable on the Notes Due 2011 is not a Business Day, then payment of interest payable on such date will be made on the next succeeding day which is a Business Day (and without any interest or other payment in respect of any such delay), in each case with the same force and effect as if made on such date. A "Business Day" shall mean any day, except a Saturday, a Sunday or a legal holiday in the City of New York on which banking institutions are authorized or required by law, regulation or executive order to close. SECTION 104. The Company, at its option, may redeem all, or, from time to time any part of the Notes Due 2011, upon notice as provided in the Indenture at a Redemption Price equal to the greater of (a) the principal amount of the Notes Due 2011 (or portion thereof) to be redeemed plus interest (if any) accrued to the Redemption Date or (b) the Make-Whole Amount with respect to the Notes Due 2011 to be redeemed. For purposes of this Section 104, the following terms shall have the following meanings: "MAKE-WHOLE AMOUNT" means the sum, as determined by a Quotation Agent, of the present values of the principal amount of the Notes Due 2011 to be redeemed, together with scheduled payments of interest (exclusive of interest to the Redemption Date) from the Redemption Date to the Stated Maturity of the Notes Due 2011, in each case discounted to the Redemption Date on a semi-annual basis, assuming a 360-day year consisting of twelve 30-day months, at the Adjusted Treasury Rate, plus accrued interest (if any) on the principal amount of the Notes Due 2011 being redeemed to the Redemption Date. "ADJUSTED TREASURY RATE" means, with respect to any Redemption Date, (i) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15 (519)" or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded U.S. Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after the remaining term of the Notes Due 2011, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined and the Adjusted Treasury Rate shall be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month) or (ii) if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date, in each case calculated on the third Business Day preceding the Redemption Date, plus in each case 0.25%. "COMPARABLE TREASURY ISSUE" means the U.S. Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term from the Redemption Date to the Stated Maturity of the Notes Due 2011 that would be utilized, at the time of selection and in 4 accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Notes Due 2011. "QUOTATION AGENT" means the Reference Treasury Dealer selected by the Trustee after consultation with the Company. "REFERENCE TREASURY DEALER" means a primary U.S. Government securities dealer selected by the Company. "COMPARABLE TREASURY PRICE" means, with respect to any Redemption Date, if clause (ii) of the definition of Adjusted Treasury Rate is applicable, the average of three, or such lesser number as is obtained by the Trustee, Reference Treasury Dealer Quotations for such Redemption Date. "REFERENCE TREASURY DEALER QUOTATIONS" means, with respect to each Reference Treasury Dealer and any Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue, expressed in each case as a percentage of its principal amount, quoted in writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third Business Day preceding such Redemption Date. The Trustee shall be under no duty to inquire into, may conclusively presume the correctness of, and shall be fully protected in acting upon the Company's calculation of any Redemption Price, including any Make-Whole Amount. The Company shall give the Trustee written notice of the Redemption Price, promptly after the calculation thereof. Notwithstanding Section 1104 of the Indenture, any notice of redemption given pursuant to said Section with respect to the foregoing redemption need not set forth the Redemption Price but only the manner of calculation thereof. SECTION 105. The Notes Due 2011 shall be defeasible pursuant to Section 1302 or 1303 of the Indenture. ARTICLE TWO FORM OF NOTES DUE 2011 SECTION 201. The Notes Due 2011 and the Trustee's certificate of authentication to be endorsed thereon are to be substantially in the following forms: Form of Face of Security: 5 UNLESS THIS CERTIFICATE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION ("DTC"), TO ARIZONA PUBLIC SERVICE COMPANY OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE, OR PAYMENT, AND ANY CERTIFICATE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR IN SUCH OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC (AND ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC), ANY TRANSFER, PLEDGE, OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL INASMUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN INTEREST HEREIN. ARIZONA PUBLIC SERVICE COMPANY 6.375% Note Due 2011 No. _________ $400,000,000 CUSIP No. 040555 CC 6 Arizona Public Service Company, a corporation duly organized and existing under the laws of Arizona (herein called the "Company", which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to Cede & Co., or registered assigns, the principal sum of Four Hundred Million Dollars on October 15, 2011, and to pay interest thereon from October 5, 2001 or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually in arrears on April 15 and October 15 in each year, commencing April 15, 2002, at the rate of 6.375%, until the principal hereof is paid or made available for payment. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest, which shall be April 1 or October 1, as the case may be, immediately preceding the Interest Payment Date (whether or not a Business Day). Any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice whereof shall be given to Holders of Securities of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange on which the Securities of this series may be listed, and upon such notice as may be required by such exchange, all as more fully provided in said Indenture. Payment of the principal of (and premium, if any) and any interest on this Security will be made at the office or agency of the Company maintained for that purpose in the City of New York, in such coin or currency of the United States of America as at the time of payment is legal tender for 6 payment of public and private debts; provided, however, that at the option of the Company payment of interest may be made by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register. Reference is hereby made to the further provisions of this Security set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place. Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Security shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose. IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed under its corporate seal. ARIZONA PUBLIC SERVICE COMPANY By ------------------------------------- Vice President, Finance Attest: --------------------------------- Vice President and Secretary Form of Reverse of Security. This Security is one of a duly authorized issue of securities of the Company (herein called the "Securities"), issued and to be issued in one or more series under an Indenture, dated as of January 15, 1998 (herein called the "Indenture", which term shall have the meaning assigned to it in such instrument), between the Company and The Chase Manhattan Bank, as Trustee (herein called the "Trustee", which term includes any successor trustee under the Indenture), and reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties and immunities thereunder of the Company, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered. This Security is one of the series designated on the face hereof, which is unlimited in aggregate principal amount. The Securities of this series are subject to redemption upon not less than 30 days' notice by mail at the option of the Company, in whole or in part, from time to time at a Redemption Price equal to the greater of (a) the principal amount of the Securities (or portion thereof) of this series to be redeemed plus interest (if any) accrued to the Redemption Date or (b) the Make-Whole Amount 7 (as defined below) with respect to the Securities of this series to be redeemed (the "Redemption Price"). If notice has been given as provided in the Indenture and funds for the redemption of any Securities (or any portion thereof) called for redemption shall have been made available on the Redemption Date referred to in such notice, such Securities (or any portion thereof) will cease to bear interest on the date fixed for such redemption specified in such notice and the only right of the Holders of such Securities will be to receive payment of the Redemption Price. Notice of any optional redemption of Securities of this series (or any portion thereof) will be given to Holders at their addresses, as shown in the Security Register for such Securities, not more than 60 nor less than 30 days prior to the date fixed for redemption. The notice of redemption will specify, among other items, the Redemption Price or, if not then known, the manner of calculation thereof, and the principal amount of the Securities of this series held by such Holder to be redeemed. If less than all of the Securities of this series are to be redeemed at the option of the Company, the Trustee shall select, in such manner as it shall deem fair and appropriate, the portion of such Securities to be redeemed in whole or in part. As used herein: "MAKE-WHOLE AMOUNT" means the sum, as determined by a Quotation Agent, of the present values of the principal amount of the Securities of this series to be redeemed, together with scheduled payments of interest (exclusive of interest to the Redemption Date) from the Redemption Date to the Stated Maturity of the Securities of this series, in each case discounted to the Redemption Date on a semi-annual basis, assuming a 360-day year consisting of twelve 30-day months, at the Adjusted Treasury Rate, plus accrued interest (if any) on the principal amount of the Securities of this series being redeemed to the Redemption Date. "ADJUSTED TREASURY RATE" means, with respect to any Redemption Date, (i) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15 (519)" or any successor publication which is published weekly by the Board of Governors of the Federal Reserve System and which establishes yields on actively traded U.S. Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after the remaining term of the Securities of this series, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined and the Adjusted Treasury Rate shall be interpolated or extrapolated from such yields on a straight line basis, rounding to the nearest month) or (ii) if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per year equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such Redemption Date, in each case calculated on the third Business Day preceding the Redemption Date, plus in each case 0.25%. 8 "COMPARABLE TREASURY ISSUE" means the U.S. Treasury security selected by the Quotation Agent as having a maturity comparable to the remaining term from the Redemption Date to the Stated Maturity of the Securities of this series that would be utilized, at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of comparable maturity to the remaining term of the Securities of this series. "QUOTATION AGENT" means the Reference Treasury Dealer selected by the Trustee after consultation with the Company. "REFERENCE TREASURY DEALER" means a primary U.S. Government securities dealer selected by the Company. "COMPARABLE TREASURY PRICE" means, with respect to any Redemption Date, if clause (ii) of the definition of Adjusted Treasury Rate is applicable, the average of three, or such lesser number as is obtained by the Trustee, Reference Treasury Dealer Quotations for such Redemption Date. "REFERENCE TREASURY DEALER QUOTATIONS" means, with respect to each Reference Treasury Dealer and any Redemption Date, the average, as determined by the Trustee, of the bid and asked prices for the Comparable Treasury Issue, expressed in each case as a percentage of its principal amount, quoted in writing to the Trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, on the third Business Day preceding such Redemption Date. The Securities of this series will not be subject to any sinking fund. In the event of redemption of this Security in part only, a new Security or Securities of this series and of like tenor for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the cancellation hereof. The Indenture contains provisions for defeasance at any time of the entire indebtedness of the Security or certain restrictive covenants and Events of Default with respect to this Security, in each case upon compliance with certain conditions set forth in the Indenture. If an Event of Default with respect to Securities of this series shall occur and be continuing, the principal of the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture. The Indenture permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Company and the Trustee without the consent of such Holders in certain limited circumstances or with the consent of the Holders of 66-2/3% in principal amount of the Securities at the time Outstanding of each series to 9 be affected. The Indenture also contains provisions permitting the Holders of specified percentages in principal amount of the Securities of each series at the time Outstanding, on behalf of the Holders of all Securities of such series, to waive compliance by the Company with certain provisions of the Indenture and certain past defaults under the Indenture and their consequences. Any such consent or waiver by the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Security. As provided in and subject to the provisions of the Indenture, the Holder of this Security shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall have previously given the Trustee written notice of a continuing Event of Default with respect to the Securities of this series, the Holders of not less than 25% in principal amount of the Securities of this series at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity, and the Trustee shall not have received from the Holders of a majority in principal amount of Securities of this series at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such proceeding, for 60 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Security for the enforcement of any payment of principal hereof or any premium or interest hereon on or after the respective due dates expressed herein. No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and any premium and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed. As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable in the Security Register, upon surrender of this Security for registration of transfer at the office or agency of the Company in any place where the principal of and any premium and interest on this Security are payable, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities of this series and of like tenor, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees. The Securities of this series are issuable only in registered form without coupons in denominations of $1,000 and any integral multiple thereof. As provided in the Indenture and subject to certain limitations therein set forth, Securities of this series are exchangeable for a like aggregate principal amount of Securities of this series and of like tenor of a different authorized denomination, as requested by the Holder surrendering the same. 10 No service charge shall be made for any such registration of transfer or exchange, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith. Prior to due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary. All terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture. Form of Trustee's Certificate of Authentication. CERTIFICATE OF AUTHENTICATION This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture. Dated: _____________________ THE CHASE MANHATTAN BANK AS TRUSTEE By ------------------------------------- AUTHORIZED OFFICER ARTICLE THREE ORIGINAL ISSUE OF NOTES DUE 2011 SECTION 301. Subject to Section 101, the Notes Due 2011 in the aggregate principal amount of $400,000,000 may, upon execution of this Fifth Supplemental Indenture, or from time to time thereafter, be executed by the Company and delivered to the Trustee for authentication, and the Trustee shall thereupon authenticate and deliver said Notes Due 2011 in accordance with a Company Order delivered to the Trustee by the Company, without any further action by the Company. ARTICLE FOUR PAYING AGENT AND REGISTRAR SECTION 401. The Chase Manhattan Bank will be the Paying Agent and Security Registrar for the Notes Due 2011. 11 ARTICLE FIVE SUNDRY PROVISIONS SECTION 501. Except as otherwise expressly provided in this Fifth Supplemental Indenture or in the form of Notes Due 2011 or otherwise clearly required by the context hereof or thereof, all terms used herein or in said form of Notes Due 2011 that are defined in the Indenture shall have the several meanings respectively assigned to them thereby. SECTION 502. The Indenture, as heretofore supplemented and amended, and as supplemented by this Fifth Supplemental Indenture, is in all respects ratified and confirmed, and this Fifth Supplemental Indenture shall be deemed part of the Indenture in the manner and to the extent herein and therein provided. SECTION 503. The Trustee hereby accepts the trusts herein declared, provided, created, supplemented, or amended and agrees to perform the same upon the terms and conditions herein and in the Indenture, as heretofore supplemented and amended, set forth and upon the following terms and conditions: The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Fifth Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made by the Company solely. In general, each and every term and condition contained in Article Six of the Indenture shall apply to and form a part of this Fifth Supplemental Indenture with the same force and effect as if the same were herein set forth in full with such omissions, variations, and insertions, if any, as may be appropriate to make the same conform to the provisions of this Fifth Supplemental Indenture. This instrument may be executed in any number of counterparts, each of which so executed shall be deemed to be an original, but all such counterparts shall together constitute but one and the same instrument. 12 IN WITNESS WHEREOF, the parties hereto have caused this Fifth Supplemental Indenture to be duly executed, and their respective corporate seals to be hereunto affixed and attested, all as of the day and year first above written. ARIZONA PUBLIC SERVICE COMPANY By: Barbara M. Gomez ------------------------------------ Barbara M. Gomez Treasurer Attest: Faye Widenmann ------------------------------------ Faye Widenmann Vice President and Secretary THE CHASE MANHATTAN BANK, as Trustee By: Natalia Rodriguez ------------------------------------ Natalia Rodriguez Assistant Vice President Attest: Virginia Dominguez ------------------------------------ Name: Virginia Dominguez Title: Trust Officer 13 STATE OF ARIZONA ) ) ss.: COUNTY OF MARICOPA ) On the 4th day of October, 2001, before me personally came Barbara M. Gomez, to me known, who, being by me duly sworn, did depose and say that she is the Treasurer of Arizona Public Service Company, one of the corporations described in and which executed the foregoing instrument; that she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the Board of Directors of said corporation; and that she signed her name thereto by like authority. Linda G. Redman ---------------------------------------- Notary Public My Commission Expires: February 8, 2003 ------------------------------------ STATE OF NEW YORK ) ) ss.: COUNTY OF NEW YORK ) On the 5th day of October, 2001, before me personally came N. Rodriguez, to me known, who, being by me duly sworn, did depose and say that he/she is an Assistant Vice President of The Chase Manhattan Bank, one of the corporations described in and which executed the foregoing instrument; that he/she knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the Board of Directors of said corporation; and that he/she signed his/her name thereto by like authority. Emily Fayan ---------------------------------------- Notary Public My Commission Expires: December 31, 2001 ------------------------------------ 14 EX-12.1 4 ex12-1.txt COMPUTATION OF EARNINGS EXHIBIT 12.1 ARIZONA PUBLIC SERVICE COMPANY COMPUTATION OF EARNINGS TO FIXED CHARGES(a) (THOUSANDS OF DOLLARS)
Nine Months Twelve Months Ended Ended December 31, -------- ------------------------------------------------------------ 9/30/01 2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- -------- Earnings: Income from continuing operations $241,801 $306,594 $268,322 $255,247 $251,493 $243,471 Income taxes .................... 156,458 195,665 133,015 133,452 129,986 103,729 Fixed Charges ................... 124,272 179,381 179,088 183,398 189,600 197,991 -------- -------- -------- -------- -------- -------- Total ........................ 522,531 681,640 580,425 572,097 571,079 545,191 ======== ======== ======== ======== ======== ======== Fixed Charges: Interest charges ................ 96,838 141,886 140,948 144,695 150,335 158,287 Amortization of debt discount ... 2,001 2,105 2,084 2,410 2,336 2,312 Estimated interest portion of annual rents ................. 25,433 35,390 36,056 36,293 36,929 37,392 -------- -------- -------- -------- -------- -------- Total fixed charges .......... 124,272 179,381 179,088 183,398 189,600 197,991 ======== ======== ======== ======== ======== ======== Ratio of Earnings to Fixed Charges (rounded down) .................. 4.20 3.79 3.24 3.11 3.01 2.75 ======== ======== ======== ======== ======== ========
---------- (a) We have reclassified certain prior year amounts to conform to the current year presentation.