-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, S6rYlynAjzPywfjaXroH/lstw1M4HJIoAx/5uvkpvZKl1nGX3PMDXllwgA9U4vkm 8dT2hSqXvybY/7ex27S4ZA== 0000950147-03-000262.txt : 20030226 0000950147-03-000262.hdr.sgml : 20030226 20030226171711 ACCESSION NUMBER: 0000950147-03-000262 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20030224 ITEM INFORMATION: Other events ITEM INFORMATION: Financial statements and exhibits FILED AS OF DATE: 20030226 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: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-04473 FILM NUMBER: 03581542 BUSINESS ADDRESS: STREET 1: 400 N FIFTH ST STREET 2: P O BOX 53999 CITY: PHOENIX STATE: AZ ZIP: 85004 BUSINESS PHONE: 6022501000 8-K 1 e-9644.txt CURRENT REPORT DATED 2/24/2003 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 8-K CURRENT REPORT Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 Date of Report (Date of earliest event reported): February 24, 2003 ARIZONA PUBLIC SERVICE COMPANY (Exact name of registrant as specified in its charter) Arizona 1-4473 86-0011170 (State or other jurisdiction (Commission (IRS Employer of incorporation) File Number) Identification Number) 400 NORTH FIFTH STREET, P.O. BOX 53999, PHOENIX, ARIZONA 85004 (Address of principal executive offices) (Zip Code) (602) 250-1000 (Registrant's telephone number, including area code) NONE (Former name or former address, if changed since last report) ITEM 5. OTHER EVENTS This Current Report on Form 8-K is limited to the reclassification of financial statements of Arizona Public Service Company (the "Company" or "APS") to reflect certain reclassifications of revenue and costs and other income and expenses and the impacts of those reclassifications on Management's Discussion and Analysis of Financial Condition and Results of Operations, Financial Statements and Notes to Financial Statements, and the Selected Financial Data as originally reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2001. NO ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER DISCLOSURES EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE RECLASSIFICATIONS DESCRIBED BELOW. THESE OTHER DISCLOSURES ARE INCLUDED IN OUR ANNUAL, QUARTERLY AND CURRENT REPORTS AND OTHER INFORMATION FILED WITH THE SEC. As previously disclosed in our Quarterly Report on Form 10-Q for the fiscal quarter ended September 30, 2002, prior to the third quarter of 2002, we recorded and reported upon settlement, sales under electricity trading contracts as revenues and purchased power costs. Effective July 1, 2002, we reclassified revenues from such electricity trading activity to a net basis of reporting which resulted in a substantial reduction in both revenues and purchased power and fuel expense but did not have any impact on our financial condition, results of operations or cash flows. In addition, we have presented in our income statements our operating revenues and purchased power and fuel separately for our electric retail, and marketing and trading segments. We also have presented our other income and expense items on a gross basis in our income statements. Our third quarter Form 10-Q, previously filed with the Securities and Exchange Commission, reflects such reclassifications. This Form 8-K Report provides updated information to substantially conform such filing to the presentation reported in our third quarter Form 10-Q. Accordingly, this report provides additional information previously reported in our Form 10-K in Item 6. Selected Financial Data, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, Item 8. Financial Statements and Supplementary Data, and Item 14. Exhibits, Financial Statements, Financial Statement Schedules and Reports on Form 8-K to reflect the aforementioned reclassifications. TABLE OF CONTENTS PAGE ---- GLOSSARY.................................................................... 3 Selected Financial Data................................................ 5 Management's Discussion and Analysis of Financial Condition and Results of Operations............................................ 6 Quantitative and Qualitative Disclosures about Market Risk............. 27 Financial Statements and Supplementary Data............................ 28 2 GLOSSARY ACC - Arizona Corporation Commission ACC Staff - Staff of the Arizona Corporation Commission ADEQ - Arizona Department of Environmental Quality AISA - Arizona Independent Scheduling Administrator ALJ - Administrative Law Judge ANPP - Arizona Nuclear Power Project, also known as Palo Verde APSES - APS Energy Services Company, Inc., a subsidiary of Pinnacle West CC&N - Certificate of Convenience and Necessity Cholla - Cholla Power Plant Citizens - Citizens Communications Company Clean Air Act - Clean Air Act, as amended Company - Arizona Public Service Company DOE - United States Department of Energy EITF - Emerging Issues Task Force EPA - United States Environmental Protection Agency ERMC - Energy Risk Management Committee FASB - Financial Accounting Standards Board FERC - United States Federal Energy Regulatory Commission FIP - Federal Implementation Plan Four Corners - Four Corners Power Plant GAAP - generally accepted accounting principles in the United States of America ISO - California Independent System Operator ITC - investment tax credit KW - kilowatt, one thousand watts KWh - kilowatt-hour, one thousand watts per hour MW - megawatt, one million watts MWh - megawatt-hours, one million watts per hour 1999 Settlement Agreement - Settlement Agreement among the Company and other parties related to the implementation of retail electric competition in Arizona NOV - Notice of Violation NRC - United States Nuclear Regulatory Commission Nuclear Waste Act - Nuclear Waste Policy Act of 1982, as amended Palo Verde - Palo Verde Nuclear Generating Station 3 PG&E - PG&E Corp. Pinnacle West - Pinnacle West Capital Corporation, parent company of the Company Pinnacle West Energy - Pinnacle West Energy Corporation, a subsidiary of Pinnacle West PPA - Purchase power agreement PRP - Potentially responsible parties under Superfund 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 SEC - United States Securities and Exchange Commission SFAS - Statement of Financial Accounting Standards Superfund - Comprehensive Environmental Response, Compensation, and Liability Act T&D - transmission and distribution WestConnect - WestConnect RTO, LLC, a proposed RTO to be formed by owners of electric transmission lines in the southwestern United States 4 SELECTED FINANCIAL DATA
2001 2000 1999 1998 1997 ----------- ----------- ----------- ----------- ----------- (DOLLARS IN THOUSANDS) Electric operating revenues Electric retail segment (a) ............... $ 2,562,088 $ 2,538,750 $ 1,914,722 $ 1,741,148 $ 1,711,134 Marketing and trading segment (a) ......... 549,240 395,392 154,126 180,145 167,419 Purchased power and fuel costs Electric retail segment ................... 1,227,188 1,065,596 432,844 306,884 284,153 Marketing and trading segment ............. 313,991 267,032 136,522 151,164 157,380 Operating expenses ........................... 1,171,171 1,155,278 1,115,664 1,097,471 1,070,517 ----------- ----------- ----------- ----------- ----------- Operating income .......................... 398,978 446,236 383,818 365,774 366,503 Other income/(deductions) .................... (79) (6,545) 20,857 20,315 21,453 Interest deductions ___ net .................. 118,211 133,097 136,353 130,842 136,463 ----------- ----------- ----------- ----------- ----------- Income before extraordinary charge and cumulative effect adjustment ........ 280,688 306,594 268,322 255,247 251,493 Extraordinary charge - net of tax (b) ..... -- -- (139,885) -- -- Cumulative effect of change in accounting - net of tax (c) ............. (15,201) -- -- -- -- ----------- ----------- ----------- ----------- ----------- Net income ................................ 265,487 306,594 128,437 255,247 251,493 Preferred dividends ....................... -- -- 1,016 9,703 12,803 ----------- ----------- ----------- ----------- ----------- Earnings for common stock ................. $ 265,487 $ 306,594 $ 127,421 $ 245,544 $ 238,690 =========== =========== =========== =========== =========== Total Assets ................................. $ 6,367,054 $ 6,413,549 $ 6,117,624 $ 6,393,299 $ 6,331,142 =========== =========== =========== =========== =========== Capital Structure: Common stock equity ....................... $ 2,150,690 $ 2,119,768 $ 1,983,174 $ 1,975,755 $ 1,849,324 Non-redeemable preferred stock ............ -- -- -- 85,840 142,051 Redeemable preferred stock ................ -- -- -- 9,401 29,110 Long-term debt less current maturities .... 1,949,074 1,806,908 1,997,400 1,876,540 1,953,162 ----------- ----------- ----------- ----------- ----------- Total capitalization .................... 4,099,764 3,926,676 3,980,574 3,947,536 3,973,647 Commercial paper .......................... 171,162 82,100 38,300 178,830 130,750 Current maturities of long-term debt ...... 125,451 250,266 114,711 164,378 104,068 ----------- ----------- ----------- ----------- ----------- Total ................................... $ 4,396,377 $ 4,259,042 $ 4,133,585 $ 4,290,744 $ 4,208,465 =========== =========== =========== =========== ===========
- ---------- See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for a discussion of certain information in the table above. (a) Amounts related to energy trading activities have been reclassified to a net basis (see Note 18). (b) Charges associated with a regulatory disallowance. See Note 1. (c) Change in accounting standards related to derivatives. See Note 16. 5 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION In this section, we explain the results of operations, general financial condition, and outlook including: * the changes in our earnings from 2000 to 2001 and from 1999 to 2000; * our capital needs, liquidity and capital resources; * our marketing and trading activities; * our financial outlook; * our critical accounting policies; * major factors that affect our financial outlook; and * our management of market risks. OVERVIEW OF OUR BUSINESS We are an Arizona electric utility and provide either retail or wholesale electric service to substantially all of the state, with the major exceptions of the Tucson metropolitan area and about one-half of the Phoenix metropolitan area. We also generate and, through Pinnacle West's marketing and trading division, sell and deliver electricity to wholesale customers in the western United States. Pinnacle West owns all of our outstanding common stock. We are required to transfer our competitive electric assets and services to one or more corporate affiliates no later than December 31, 2002. Consistent with that requirement, we have been addressing the legal and regulatory requirements necessary to complete the transfer of our generation assets to Pinnacle West Energy before that date. As we discuss in greater detail below under "Business Outlook - Other Factors Affecting Our Financial Outlook," recent Arizona regulatory developments have raised uncertainty about the status and pace of retail electric competition in Arizona, including our transfer of generation assets to Pinnacle West Energy. BUSINESS SEGMENTS We have two principal business segments (determined by products, services and regulatory environment), which consist of regulated retail electricity business and related activities (electric retail business segment) and competitive business activities (marketing and trading segment). Our electric retail business segment currently includes activities related to electricity transmission and distribution, as well as electricity generation. Our marketing and trading segment currently includes activities related to wholesale marketing and trading. 6 These reportable segments reflect a change in the reporting of our segment information. Before the fourth quarter of 2001, we had two segments (generation and delivery). The "generation segment" information combined our marketing and trading activities with our generation of electricity activities. The "delivery segment" included transmission and distribution activities. In the fourth quarter, we filed with the ACC a request for a proposed rule variance and approval of a purchase power agreement (see Note 3) that inherently views our business in the new reportable segments described herein. Internal management reporting has been changed to reflect this alignment. See "Business Segments" in Note 15 for more information about our business segments. The following is a summary of earnings by business segment for 2001, 2000, and 1999 (dollars in millions): 2001 2000 1999 ----- ----- ----- Electric Retail $ 140 $ 230 $ 257 Marketing and trading 140 77 10 ----- ----- ----- Income from continuing operations 280 307 267 Extraordinary charge - net of income taxes -- -- (140) Cumulative effect of change in accounting - net of income taxes (15) -- -- ----- ----- ----- Earnings for common stock $ 265 $ 307 $ 127 ===== ===== ===== Throughout this section, we refer to specific "Notes" in the Notes to Financial Statements. These Notes add further details to the discussion. 7 RESULTS OF OPERATIONS 2001 COMPARED WITH 2000 Our net income for the year ended December 31, 2001 was $265 million compared with $307 million for the year ended December 31, 2000. In 2001, we recognized a $15 million after-tax loss in net income as a cumulative effect of a change in accounting for derivatives. See Note 16 for further discussion on accounting for derivatives. Income before accounting change for the year ended December 31, 2001 was $281 million compared with $307 million for the year ended December 31, 2000. The year-to-year comparison benefited from strong marketing and trading results and retail customer growth. These factors were partially offset by higher purchased power and fuel costs, due in part to increased power plant maintenance; generation reliability measures; continuing retail electricity price decreases; and a charge related to Enron and its affiliates. The major factors that increased (decreased) income before accounting change were as follows (dollars in millions):
Increase (Decrease) ---------- Increases (decreases) in marketing and trading and electric retail segments' revenues, net of purchased power and fuel expense due to: Marketing and trading activities: Increase from generation sales other than native load due to higher market prices $ 25 Decrease in other realized marketing and trading in current period primarily due to less transactions (7) Change in prior period mark-to-market value for commodity contracts delivered in current period 18(a) Increase in mark-to-market value related to future periods 71(a) ---- Net increase in marketing and trading 107 Higher replacement power costs for plant outages related to higher market prices (70) Higher purchased power costs related to 2001 generation reliability program (30) Retail price reductions (see Note 3) (27) Charges related to purchased power contracts with Enron and its affiliates (13)(b) Miscellaneous revenues 1 ---- Total decrease in marketing and trading and electric retail segments' revenues, net of purchased power and fuel expense (32) Higher operations and maintenance expense related to 2001 generation reliability program (12) Higher operations and maintenance expense related primarily to employee benefits, plant outage and maintenance, and other costs (23) Lower net interest expense primarily due to lower interest rates 15 Higher other net income 10 Miscellaneous items, net 3 ---- Net decrease in income before income taxes (39) Lower income taxes primarily due to lower income 13 ---- Net decrease in income before accounting change $(26) ====
8 (a) Essentially all of our marketing and trading activities are structured activities. This means our portfolio of forward sales positions is hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. (b) We recorded charges totaling $13 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. Marketing and trading and electric retail segments' revenues increased approximately $177 million because of: * changes in marketing and trading revenues ($154 million, net increase) due to: - increased revenues related to generation sales other than native load as a result of higher average market prices ($32 million); - increased realized revenues related to other marketing and trading in current period primarily due to more transactions and higher market prices ($40 million); - increased prior period mark-to-market value for losses transferred to realized margin in current period ($11 million); - increased mark-to-market value for future periods primarily as a result of more forward sales volumes ($71 million); * decreased revenues related to other wholesale sales and miscellaneous revenues as a result of sales volumes ($28 million); * increased retail revenues primarily related to higher sales volumes primarily due to customer growth ($78 million); and * decreased retail revenues related to reductions in retail electricity prices ($27 million). Purchased power and fuel expenses increased approximately $209 million primarily because of: * changes in marketing and trading purchased power and fuel costs ($47 million, net increase) due to: - increased fuel costs related to generation sales other than native load as a result of higher fuel prices ($7 million); - increased fuel and purchased power costs related to other realized marketing and trading in current period primarily due to more transactions ($47 million); - decreased mark-to-market fuel costs related to accounting for derivatives ($7 million) (see Note 16); * decreased costs related to other wholesale sales as a result of lower volumes ($29 million); * higher replacement power costs primarily due to higher market prices and increased plant outages ($70 million), including costs of $12 million related to a Palo Verde outage extension to replace fuel control element assemblies; * higher purchase power costs related to 2001 generation reliability program ($30 million); * higher costs related to retail sales volumes due to customer growth ($78 million); and * charges related to purchased power contracts with Enron and its affiliates ($13 million). The increase in operations and maintenance expenses of $35 million primarily related to the 2001 generation summer reliability program (the 9 addition of generating capability to enhance reliability for the summer of 2001 ($12 million)) and increased employee benefit costs, plant outage and maintenance, and other costs ($23 million). Other net income increased $10 million primarily because of insurance recovery of environmental remediation costs. Interest expense decreased by $15 million primarily because of lower interest rates and increased capitalized interest resulting from higher construction project balances. 2000 COMPARED WITH 1999 Our earnings for the year ended December 31, 2000 were $307 million compared with $127 million for the year ended December 31, 1999. Our 2000 earnings increased $180 million over 1999 primarily because of a $140 million after-tax extraordinary charge that we recorded in 1999. This charge reflected a regulatory disallowance resulting from an ACC-approved Settlement Agreement related to the implementation of retail electric competition. See "Regulatory Agreements" below and Notes 1 and 3 for additional information about the 1999 Settlement Agreement and the resulting regulatory disallowance. Earnings excluding the extraordinary charge increased $39 million, or 15%, over 1999 primarily because of increases in wholesale and retail electric sales. These positive factors more than offset decreases resulting from the completion of ITC amortization in 1999, reductions in retail electricity prices, and miscellaneous factors. See "Regulatory Agreements" below and Note 3 for information on the price reductions. See "Regulatory Agreements" below and Note 4 for additional information about ITC amortization. The major factors that increased (decreased) earnings were as follows (dollars in millions):
Increase (Decrease) ---------- Increases (decreases) in marketing and trading and electric retail segments' revenues, net of purchased power and fuel expense due to: Marketing and trading activities: Increase from generation sales other than native load due to higher market prices $ 47 Increase in other realized marketing and trading in current period primarily due to more transactions 53 Change in prior period mark-to-market value for commodity contracts delivered in current period (2)(a) Increase in mark-to-market value related to future periods 13 (a) ---- Net increase in marketing and trading 111 Retail price reductions (see Note 3) (28) Higher retail sales primarily related to customer growth 10 Miscellaneous revenues 9 ---- Total increase in marketing and trading and electric retail segments' revenues, net of purchased power and fuel expense 102
10 Lower operations and maintenance expense related primarily to $19 million of non-recurring items recorded in 1999 partially offset by increased costs related to customer growth 7 Higher depreciation and amortization expense (9) Miscellaneous items, net 2 ---- Net increase in income before income taxes 102 Higher income taxes due to higher income in 2000 and higher ITC amortization in 1999 (63) ---- Net increase in income before extraordinary charge and accounting change $ 39 ====
(a) Essentially all of our marketing and trading activities are structured activities. This means our portfolio of forward sales positions is hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Marketing and trading and electric retail segments' revenues increased approximately $865 million because of: * changes in marketing and trading revenues ($241 million, net increase) due to: - increased revenues related to generation sales other than native load as a result of higher market prices ($86 million); - increased realized revenues related to other marketing and trading in current period primarily due to more transactions and higher market prices ($144 million); - decreased prior period mark-to-market value for gains transferred to realized margin in current period ($2 million); - increased mark-to-market value for future periods primarily as a result of more forward sales volumes ($13 million); * increased revenues related to increased volumes and higher market prices for other wholesale sales resulting from retail load hedging activities and miscellaneous revenues ($523 million); * increased retail revenues primarily related to higher sales volumes due to customer growth ($129 million); and * decreased retail revenues related to reductions in retail electricity prices ($28 million). Purchased power and fuel expenses increased approximately $763 million primarily due to: * changes in marketing and trading purchased power and fuel costs ($130 million, net increase) due to: - increased fuel costs related to generation sales other than native load as a result of higher fuel prices ($39 million); - increased fuel and purchased power costs related to other realized marketing and trading in current period primarily due to more transactions ($91 million); * increased costs related to increased volumes and higher market prices for wholesale sales resulting from retail hedging activities ($513 million); and * higher costs related to retail sales volumes due to customer growth and increased fuel and purchased power prices ($120 million). 11 The decrease in operations and maintenance expenses of $7 million primarily related to $19 million of non-recurring items recorded in 1999 partially offset by increased costs related to customer growth. The increase in depreciation and amortization of $9 million primarily related to higher plant in service balances offset by lower regulatory asset amortization. REGULATORY AGREEMENTS Regulatory agreements approved by the ACC affect the results of our operations. The following discussion focuses on three agreements approved by the ACC, each of which included retail electricity price reductions: * The 1999 Settlement Agreement to implement retail electric competition; * A 1996 agreement that accelerated the amortization of our regulatory assets; and * A 1994 settlement that accelerated the amortization of our deferred ITCs. 1999 SETTLEMENT AGREEMENT As part of the 1999 Settlement Agreement, we agreed to reduce retail electricity prices for standard-offer, full-service customers with loads less than three megawatts in a series of annual decreases of 1.5% on 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 required by the 1996 regulatory agreement (see below). For customers having loads three megawatts or greater, standard-offer rates will be reduced in annual increments that total 5% in the years 1999 through 2002. The 1999 Settlement Agreement also removed, as a regulatory disallowance, $234 million before income taxes ($183 million net present value) from ongoing regulatory cash flows. We recorded this regulatory disallowance as a net reduction of regulatory assets and reported it as a $140 million after-tax extraordinary charge on the 1999 income statement. Under the 1996 regulatory agreement, we were recovering substantially all of our regulatory assets through accelerated amortization over an eight-year period that would have ended June 30, 2004. For more details, see Note 1. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions): 1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total ---- ---- ---- ---- ---- ---- ----- $164 $158 $145 $115 $ 86 $ 18 $686 12 See Note 3 and "Business Outlook - Electric Competition (Retail)" below for additional information regarding the 1999 Settlement Agreement. 1996 REGULATORY AGREEMENT As part of the 1996 regulatory agreement, we reduced our retail electricity prices by 3.4% effective July 1, 1996. This reduction decreased electric revenue by about $49 million annually ($29 million after income taxes). We also agreed to share future cost savings with our customers during the term of this agreement, which resulted in the following additional retail price reductions: * $18 million annually ($11 million after income taxes), or 1.2%, effective July 1, 1997; * $17 million annually ($10 million after income taxes), or 1.1%, effective July 1, 1998; and * $11 million annually ($7 million after income taxes), or 0.7%, effective July 1, 1999 (as noted above, this reduction was included in the July 1, 1999 price reduction under the 1999 Settlement Agreement). 1994 RATE SETTLEMENT As part of a 1994 rate settlement, we accelerated amortization of substantially all of our ITCs over a five-year period that ended on December 31, 1999. The amortization of ITCs decreased annual income tax expense by about $28 million. Beginning in 2000, no further benefits were reflected in income tax expense related to the acceleration of the ITCs (see Note 4). LIQUIDITY AND CAPITAL RESOURCES CAPITAL NEEDS AND RESOURCES CAPITAL EXPENDITURE REQUIREMENTS The following table summarizes the actual capital expenditures for the year ended December 31, 2001 and estimated capital expenditures for the next three years. 13 CAPITAL EXPENDITURES (dollars in millions) (actual) (estimated) -------- -------------------------- 2001 2002 2003 2004 ---- ---- ---- ---- Delivery $354 $349 $271 $280 Generation (a) 117 149 -- -- ---- ---- ---- ---- Total $471 $498 $271 $280 ==== ==== ==== ==== (a) Pursuant to the 1999 Settlement Agreement, we are required to transfer our competitive electric assets and services no later than December 31, 2002. We and the other Palo Verde participants are currently considering issues related to replacement of the steam generators in Units 1 and 3. Although a final determination of whether Units 1 and 3 will require steam generator replacement to operate over their current full licensed lives has not yet been made, the other participants and us have approved an expenditure in 2002 to procure long lead-time materials for fabrication of a spare set of steam generators for either Unit 1 or 3. Our portion of this expenditure is approximately $7 million and is included in the estimated expenditures above. This action will provide the other Palo Verde participants and us an option to replace the steam generators at either Unit 1 or 3 as early as fall 2005 should we ultimately choose to do so. If the participants decide to proceed with steam generator replacement at both Units 1 and 3, we have estimated that our portion of the fabrication and installation costs and associated power uprate modifications would be approximately $130 million over the next seven years, which would be funded with internally-generated cash or external financings. Generation capital expenditures are comprised of multiple improvements for our existing fossil and nuclear plants. Examples of the types of projects included in this category are additions, upgrades and capital replacements of various power plant equipment such as turbines, boilers, and environmental equipment. The increase in this category in 2002 is due primarily to Four Corners and various gas-fired units. The increased work on equipment is due to higher use of the units and also a stack replacement project for Four Corners Units 1 and 2. The 2002 generation category also contains approximately $30 million of nuclear fuel expenditures. Delivery capital expenditures are comprised of transmission and distribution (T&D) infrastructure additions and upgrades, capital replacements, new customer construction, and related information systems and facility costs. Examples of the types of projects included in the forecast include T&D lines and substations, line extensions to new residential and commercial developments, and upgrades to customer information systems. In addition, we began several major transmission projects in 2001. These projects are periodic in nature and are driven by strong regional customer growth. We expect to spend about $150 million on major transmission projects during the 2002-2004 time frame. 14 CAPITAL RESOURCES AND CASH REQUIREMENTS We had lines of credit available in the amount of $250 million at December 31, 2001. There was no outstanding balance on our lines of credit at December 31, 2001. We project that these lines of credit will be available over the next three years. The lines of credit are anticipated to be renewed at their expiration dates. See Note 5 for further information on our lines of credit. We have obtained approximately $500 million in letters of credit primarily to provide credit support for our variable rate tax-exempt bonds and our Palo Verde sale-leaseback transactions. We do not have ratings triggers in any of our debt agreements. Ratings triggers are provisions that would result in the acceleration of repayment obligations based upon a credit rating agency downgrade. Although those rating triggers appear in certain power marketing and trading agreements, their financial impacts are not expected to be significant. Our first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel, transportation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. These conditions did not exist at December 31, 2001. Our capital requirements consist primarily of capital expenditures and optional and mandatory redemptions of long-term debt. We pay for our capital requirements with cash from operations and, to the extent necessary, external financing. We pay for our dividends to Pinnacle West with cash from operations. During the period from 1999 through 2001, we paid for substantially all of our capital expenditures with cash from operations. We expect to do so in 2002 through 2004 with cash from operations and our debt issuances. See the capital expenditure table above for additional information regarding actual capital expenditures in 2001 and projected capital expenditures for the next three years. 15 The following table summarizes cash commitments for the year ended December 31, 2001 and estimated commitments for the next three years (dollars in millions): (actual) (estimated) -------- -------------------- 2001 2002 2003 2004 ---- ---- ---- ---- Long-term debt repayments (see Note 6) $384 $247 $ -- $205 Operating leases payments (see Note 8) 62 63 61 61 Fuel and purchase power commitments (see Note 10) 374 252 124 80 ---- ---- ---- ---- Total cash commitments $820 $562 $185 $346 ==== ==== ==== ==== Based on market conditions and call provisions, we may make optional redemptions of long-term debt from time to time. As of December 31, 2001, we had credit commitments from various banks totaling about $250 million, which were available either to support the issuance of commercial paper or to be used as bank borrowings. At the end of 2001, we had about $171 million of commercial paper outstanding and no long-term bank borrowings. Our long-term debt was approximately $2.1 billion at December 31, 2001 and 2000 (see Note 6). Although ACC financing orders establish maximum amounts of additional debt that we may issue, we do not expect these orders to limit our ability to meet our capital requirements. On March 1, 2002, we issued $375 million of 6.50% Notes due 2012. On March 15, 2002, we announced the redemption on April 15, 2002 of approximately $125 million of our First Mortgage Bonds, 8.75% Series due 2024. CRITICAL ACCOUNTING POLICIES In preparing the financial statements in accordance with generally accepted accounting principles (GAAP), management must often make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses, and related disclosures at the date of the financial statements and during the reporting period. Some of those judgments can be subjective and complex, and actual results could differ from those estimates. Our most critical accounting policies include the determination of the appropriate accounting for our derivative instruments, mark-to-market accounting and the impacts of regulatory accounting on our financial statements. See Note 1 for a discussion of these critical accounting policies. 16 OTHER ACCOUNTING MATTERS In June 2002, the FASB's EITF issued certain guidance related to energy trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." The new guidance, which was effective July 1, 2002, required that all energy trading activities within the scope of EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," be presented on a net basis in revenues and that prior period amounts be restated. In October 2002, the EITF reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" should be shown net in the income statement if the derivative is held for trading purposes. This decision effectively supersedes the guidance provided at the June meeting. Historically, we have reported our electric revenues and purchased power and fuel costs on a gross basis in our statements of income, with the exception of unrealized gains and losses recorded under the mark-to-market method. When the gain or loss was realized, the gross amount was recorded as revenue and purchased power and fuel costs in the statements of income. Throughout this document, we have made the reclassification change to net revenues and purchased power and fuel costs related to our energy trading activities. This change has no impact on our gross margin, net income or cash provided by operating activities. The following table shows the impact of the change on our Marketing and Trading segment revenues and purchased power and fuel costs: Year ended December 31, (dollars in thousands) ------------------------------ 2001 2000 1999 -------- -------- -------- Marketing and trading segment revenues before reclassification $748,704 $941,502 $378,076 Less: Purchased power and fuel costs netted with revenues 199,464 546,110 223,950 -------- -------- -------- Marketing and trading segment revenues after reclassification $549,240 $395,392 $154,126 ======== ======== ======== Marketing and trading segment purchased power and fuel before reclassification $513,455 $813,142 $360,472 Less: Purchased power and fuel costs netted with revenues 199,464 546,110 223,950 -------- -------- -------- Marketing and trading segment purchased power and fuel after reclassification $313,991 $267,032 $136,522 ======== ======== ======== 17 In the October 2002 meeting, the EITF also rescinded EITF 98-10. This guidance is effective immediately for all new contracts and on January 1, 2003 for existing contracts. As such, energy trading contracts will be accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received, unless the contracts are required to be marked to market as derivatives under SFAS No. 133 or if allowed by other guidance. For existing contracts, we will record a cumulative effect adjustment in net income for the previously recorded accumulated unrealized mark-to-market on energy trading contracts that do not meet the definition of a derivative under SFAS No. 133. We are currently evaluating the impact of this guidance on our financial statements. 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. As a result of the 1999 Settlement Agreement (see "Regulatory Agreements" above and Note 3), we 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, we reported a regulatory disallowance ($140 million after income taxes) as an extraordinary charge on the 1999 income statement. See Note 1 for additional information on regulatory accounting and Note 3 for additional information on the 1999 Settlement Agreement. Effective January 1, 2001, we adopted SFAS No. 133. SFAS No. 133 requires that entities recognize all derivatives as either assets or liabilities on the balance sheets and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are either recognized periodically in income or stockholders' 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 commodity 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 other comprehensive income. As a result of adopting SFAS No. 133 in 2001, we recorded a $15 million after-tax loss in net income and a $72 million after-tax gain in equity (as a component of other comprehensive income), both as a cumulative effect of a change in accounting principle. The loss primarily resulted from electricity options contracts. The gain resulted from unrealized gains on cash flow hedges. See Note 16 for further information on accounting for derivatives under SFAS No. 133, including discussions on new guidance effective on April 1, 2002. 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 Accounting Principles Board Opinion No. 17, "Intangible Assets." This standard is effective for the year beginning January 1, 2002. We have no goodwill recorded in the balance sheets. The impacts of this new standard are not material to our financial statements. 18 The FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," in August 2001. 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. 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. This standard does not impact our financial statements at adoption. In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), "Accounting for Certain Costs Related to Property, Plant and Equipment (PP&E)." This proposed SOP would create a project timeline framework for capitalizing costs related to PP&E construction, require that PP&E assets be accounted for at the component level and require administrative and general cost incurred in support of capital projects to be expensed in the current period. The AICPA plans to issue the final SOP in the fourth quarter of 2002. We are currently evaluating the impacts of the proposed SOP. In 1986, we entered into agreements with three separate special purpose entity (SPE) lessors in order to sell and lease back interests in Palo Verde Unit 2 (see Note 8). The leases are accounted for as operating leases in accordance with GAAP. In February 2002, the FASB discussed issues related to special purpose entities. It is expected that FASB will issue additional guidance on accounting for SPEs later this year. As a result of future FASB actions, we may be required to consolidate the SPEs in our financial statements. If consolidation is required, the assets and liabilities of the SPEs that relate to the sale-leaseback transactions would be reflected on our balance sheets. The SPE debt that is not reflected on our balance sheets is approximately $300 million at December 31, 2001. Rating agencies have already considered this debt when evaluating our credit ratings. BUSINESS OUTLOOK FINANCIAL OUTLOOK For 2001, our reported income before accounting change was $281 million and included charges totaling $13 million before income taxes that we do not expect to recur related to our exposure to Enron and its affiliates. Our earnings in 2002 are expected to be negatively affected by the completed transition to Pinnacle West in 2001 of marketing and trading activities, as well as retail electricity price decreases. These negative factors are expected to be partially offset in 2002 by the absence of significant expenses for reliability and power plant outages that we incurred in 2001 that we do not expect to recur in 2002 and by retail customer growth, although the pace of growth is expected to be slower than in the past. These factors are described in more detail below. 19 As of December 31, 2001, we completed the transition of marketing and trading activities to Pinnacle West's marketing and trading division. In 2001, we recorded the following pretax amounts related to marketing and trading activities: $549 million of electric operating revenues and $314 million of purchased power and fuel costs. During 2001, in order to meet the highest customer demand in our history, we incurred significant expenses for our summer reliability program and for higher replacement power costs related to power plant outages. These efforts cost approximately $140 million before income taxes, which is not expected to be repeated in 2002. See "Results of Operations - 2001 Compared with 2000" above. We estimate our retail customer growth in 2002 to be 3.2%, which is slower than the pace of growth in recent years, although still about three times the national average. Our customer growth in 2001 was 3.7%. We expect the customer growth rate to be weak in the first two quarters of 2002, then begin a rebound. Our current estimate for customer growth in 2003 and 2004 is between 3.5% and 4.0% annually. The retail price decreases are described above in "Results of Operations - Regulatory Agreements." The foregoing discussion of future expectations is forward-looking information. Actual results may differ materially from expectations. See "Forward-Looking Statements" below. OTHER FACTORS AFFECTING OUR FINANCIAL OUTLOOK COMPETITION AND INDUSTRY RESTRUCTURING ELECTRIC COMPETITION (WHOLESALE) The FERC regulates rates for wholesale power sales and transmission services. Pinnacle West's marketing and trading division sells in the wholesale market our generation production output that is not needed for our native load and, in doing so, competes with other utilities, power marketers, and independent power producers. Wholesale market prices significantly fell during 2001 and remain low for the reasons discussed under "Financial Outlook" above. We cannot predict whether these lower prices will continue, or whether changes in various factors that affect demand and capacity, including regulatory actions, will cause the market prices to rise during 2002 or thereafter. 20 ELECTRIC COMPETITION (RETAIL) On September 21, 1999, the ACC approved Rules that provide a framework for the introduction of retail electric competition in Arizona. A Maricopa County, Arizona, Superior Court later found the Rules unlawful and unconstitutional; however, the Rules remain in effect pending the outcome of appeals. See "Retail Electric Competition Rules" in Note 3 for additional information about the Rules and the outstanding legal challenges to the Rules. Although the Rules allow retail customers to have access to competitive providers of energy and energy services, we are the "provider of last resort" for standard-offer, full service customers under rates that have been approved by the ACC. These rates are established until July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing 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. Energy prices in the western U.S. wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. 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 1999 Settlement Agreement, there can be no assurance that we would be able to fully recover the costs of this power. On September 23, 1999, the ACC approved a comprehensive 1999 Settlement Agreement among us and various parties related to the implementation of retail electric competition in Arizona. See "1999 Settlement Agreement" in Note 3 for additional information about the 1999 Settlement Agreement, including the recent resolution of legal challenges to the 1999 Settlement Agreement. Under the Rules, as modified by the 1999 Settlement Agreement, we are required to transfer our competitive electric assets and services either to an unaffiliated party or to a separate corporate affiliate no later than December 31, 2002. Consistent with that requirement, we have been addressing the legal and regulatory requirements necessary to complete the transfer of our generation assets to Pinnacle West Energy on or before that date. In anticipation of our transfer of generation assets, Pinnacle West Energy has completed, and is in the process of developing and planning, various generation expansion projects so that we can reliably meet the energy requirements of our Arizona customers. Following the transfer of our fossil-fueled generation assets and the receipt of certain regulatory approvals, Pinnacle West Energy expects to sell its power at wholesale to Pinnacle West's marketing and trading 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: * grant us a partial variance from an ACC Rule that would obligate us to acquire all of our customers' standard-offer generation requirements 21 from the competitive market (with at least 50% of those requirements coming from a "competitive bidding" process) starting in 2003; and * approve as just and reasonable a long-term purchase power agreement between us and Pinnacle West. We requested these ACC actions to ensure ongoing reliable service to our standard-offer, full-service customers in a volatile generation market and to recognize Pinnacle West Energy's significant investment to serve our load. See "Proposed Rule Variance and Purchase Power Agreement" in Note 3 for additional information about our October 2001 ACC filing. On February 8, 2002, the ACC's Chief ALJ issued a procedural order which consolidated the ACC docket relating to our October 2001 filing with several other pending ACC dockets, including a "generic" docket request by the ACC Chairman to "determine if changed circumstances require the [ACC] to take another look at restructuring in Arizona." Although the order consolidates several dockets, it states that a hearing on the matter will commence on April 29, 2002. The order went on to state that, contrary to our position, the ALJ was construing the October 2001 filing as a request by us to amend the 1999 ACC order that approved the 1999 Settlement Agreement. On March 22, 2002, the ACC Staff issued a report to the ACC recommending that the ACC address the following issues in the generic docket: * The extent and manner of the ACC's involvement in monitoring market conditions and/or mitigating the development of market power for generation and transmission; * The lack of guidance in the Rules regarding the mechanics of the "competitive bidding process" referenced above; * The consideration of alternatives to the transfer of generation assets required by the Rules (the ACC Staff stated that such transfers would be "unwise" at the present time and recommended that "all transfer and separation of utilities' assets be stayed pending the completion of the generic docket"); * The consideration of transmission constraints that could impact the development of the wholesale power market; * The reassessment of adjustor mechanisms for standard-offer rates in light of problems with the development of a wholesale power market; and * The adequacy of customer "shopping credits" in the context of the development of a competitive retail market (a shopping credit is the cost a customer does not pay to a utility distribution company if the customer obtains generation from another party). Although not a specific ACC Staff recommendation, the report was also critical of certain aspects of the proposed purchase power agreement between the Company and Pinnacle West. 22 A modification to the Rules or the 1999 Settlement Agreement as a result of the consolidated docket could, among other things, adversely affect our ability to transfer our generation assets to Pinnacle West Energy by December 31, 2002. We cannot predict the outcome of the consolidated docket or its effect on the specific requests in our October 2001 filing, the existing Arizona electric competition rules, or the 1999 Settlement Agreement. As a result of the foregoing matters, as well as energy market developments, including those relating to California's failed deregulation efforts and to Enron's recent bankruptcy filing, electric utility restructuring is in a state of flux in the western United States, including Arizona, and around the country. CALIFORNIA ENERGY MARKET ISSUES See Note 10 for information regarding California energy market issues. FACTORS AFFECTING OPERATING REVENUES Electric operating revenues are derived from sales of electricity in regulated retail markets in Arizona, and from competitive retail and wholesale bulk power markets in the western United States. These revenues are expected to be affected by electricity sales volumes related to customer mix, customer growth and average usage per customer, as well as electricity prices and variations in weather from period to period. In 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 about 4% a year for the three years 1999 through 2001; we currently expect customer growth to be about 3.2% in 2002 and between 3.5% and 4.0% a year in 2003 and 2004. We currently estimate that retail electricity sales in kilowatt-hours will grow 3.5% to 5.5% a year in 2002 through 2004, 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. As previously noted, under the 1999 Settlement Agreement, we have annual retail electricity price reductions of 1.5% through July 1, 2003 (see Note 3). 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, new generating plants being placed in service, and our hedging program for managing such costs. See "Generating Fuel and Purchased Power-Natural Gas Supply" in Part I for additional information on a pending dispute related to a natural gas-fired transportation contract with El Paso Natural Gas Company. 23 Operations and maintenance expenses are expected to be affected by sales mix and volumes, power plant operations, inflation, outages 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 1 for the regulatory asset amortization that is being recorded in 1999 through 2004 pursuant to the 1999 Settlement Agreement. Also, see Note 1 regarding current depreciation rates. 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. The average property tax rate for us was 9.32% for 2001 and 9.16% for 2000. We expect property taxes to increase primarily due to our additions to existing facilities. Interest expense is affected by the amount of debt outstanding and the interest rates on that debt. The primary factors affecting borrowing levels in the next several years are expected to be our internally-generated cash flow. We cannot accurately predict the impact of full retail competition on our financial position, cash flows, results of operations, or liquidity. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete effectively in a restructured industry. Our financial results may be affected by the application of SFAS No. 133. See "Critical Accounting Policies" above and Note 16 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. MARKET RISKS Our operations include managing market risks related to changes in interest rates, commodity prices, and investments held by the nuclear decommissioning trust fund. INTEREST RATE AND EQUITY RISK Our major financial market risk exposure is changing interest rates. Changing interest rates will affect interest paid on variable-rate debt and interest earned by our nuclear decommissioning trust fund (see Note 11). 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. The tables below present contractual balances of our long-term debt and commercial paper at the expected maturity dates as well as the fair value of 24 those instruments on December 31, 2001 and 2000. The interest rates presented in the tables below represent the weighted average interest rates for the years ended December 31, 2001 and 2000. Expected Maturity/Principal Repayment December 31, 2001 (dollars in thousands)
Variable-Rate Fixed-Rate Short-Term Debt Long-Term Debt Long-Term Debt --------------------- --------------------- -------------------- Interest Interest Interest Rates Amount Rates Amount Rates Amount ----- ----------- ----- ----------- ----- ----------- 2002 4.72% $ 171,162 $ -- 8.10% $ 125,451 2003 -- -- 6.18% 337 2004 -- -- 6.08% 205,185 2005 -- -- 7.59% 400,185 2006 -- -- 6.77% 83,880 Years thereafter -- 2.60% 476,860 6.73% 787,894 ----------- ----------- ----------- Total $ 171,162 $ 476,860 $ 1,602,932 =========== =========== =========== Fair Value $ 171,162 $ 476,860 $ 1,621,937 =========== =========== ===========
Expected Maturity/Principal Repayment December 31, 2000 (dollars in thousands)
Variable-Rate Fixed-Rate Short-Term Debt Long-Term Debt Long-Term Debt --------------------- --------------------- -------------------- Interest Interest Interest Rates Amount Rates Amount Rates Amount ----- ----------- ----- ----------- ----- ----------- 2001 6.64% $ 82,100 7.33% $ 250,000 7.75% $ 266 2002 -- -- 8.13% 125,000 2003 -- -- 7.75% 443 2004 -- -- 6.17% 205,000 2005 -- -- 7.28% 400,000 Years thereafter -- 4.06% 476,860 7.48% 605,598 ----------- ----------- ----------- Total $ 82,100 $ 726,860 $ 1,336,307 =========== =========== =========== Fair Value $ 82,100 $ 726,860 $ 1,393,251 =========== =========== ===========
COMMODITY PRICE RISK 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 25 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 and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. In addition, subject to specified risk parameters established by the Pinnacle West Board of Directors and monitored by Pinnacle West's ERMC, we engage in trading activities intended to profit from market price movements. In accordance with Emerging Issues Task Force (EITF) 98-10 "Accounting For Contracts Involved in Energy Trading and Risk Management Activities", such trading positions are marked-to-market (see Note 18). These trading activities are part of our marketing and trading activities and are reflected in the marketing and trading revenues and expenses. The following schedule shows the changes in mark-to-market of our trading positions during the years ended December 31, 2001 and 2000 (dollars in millions): 2001 2000 ----- ----- Mark-to-market of net trading positions at beginning of year $ 12 $ -- Prior period mark-to-market (gains) losses realized during the year 7 (2) Change in mark-to-market gains for future period activities 85 14 Transfer of mark-to-market balance to Pinnacle West marketing and trading (104) -- ----- ----- Mark-to-market of net trading positions at end of year $ -- $ 12 ===== ===== As of December 31, 2001, a hypothetical adverse price movement of 10% in the market price of our risk management and trading assets and liabilities that would have decreased the fair market value of these contracts by approximately $23 million, compared to a $28 million decrease that would have been realized as of December 31, 2000. A hypothetical favorable price movement of 10% would have increased the fair market value of these contracts by approximately $23 million, compared to a $28 million increase that would have been realized as of December 31, 2000. These contracts are hedges of our forecasted purchases of natural gas. The impact of these hypothetical price movements would substantially offset the impact that these same price movements would have on the physical exposures being hedged. We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of this and all other counterparties. Despite the fact that the great majority of our 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. Counterparties in the portfolio consist principally of major energy companies, municipalities, and local distribution companies. We maintain credit 26 policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Credit reserves are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 for a discussion of our credit reserve policy. FORWARD-LOOKING STATEMENTS The above discussion 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, including the introduction of retail electric competition in Arizona and our October 2001 ACC filing; 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 the FERC in June 2001; regional economic and market conditions, including the California energy situation and completion of generation construction in the region, 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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK See "Market Risks" for a discussion of quantitative and qualitative disclosures about market risk. 27 FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO FINANCIAL STATEMENTS Report of Management..........................................................29 Independent Auditors' Report..................................................30 Statements of Income for 2001, 2000 and 1999..................................31 Balance Sheets as of December 31, 2001 and 2000...............................32 Statements of Cash Flows for 2001, 2000 and 1999..............................34 Statements of Changes in Common Stock Equity for 2001, 2000 and 1999..........35 Notes to Financial Statements.................................................36 Financial Statement Schedule for 2001, 2000 and 1999 Schedule II - Reserve for 2001, 2000 and 1999.....................................................77 See Note 12 of Notes to Financial Statements for the selected quarterly financial data required to be presented in this Item. 28 REPORT OF MANAGEMENT The responsibility for the integrity of our financial information rests with management, which has prepared the accompanying financial statements and related information. This information was prepared in accordance with generally accepted accounting principles as appropriate in the circumstances, and based on management's best estimates and judgments. These financial statements have been audited by independent auditors and their report is included on the following page. Management maintains and relies upon systems of internal control. A limiting factor in all systems of internal control is that the cost of the system should not exceed the benefits to be derived. Management believes that our system provides the appropriate balance between such costs and benefits. Periodically the internal control system is reviewed by both our internal auditors to test for compliance and our independent auditors in conjunction with their audit of our financial statements. Reports issued by the internal auditors are released to management, and such reports or summaries thereof are transmitted to the Audit Committee of the Board of Directors and the independent auditors on a timely basis. By letter dated February 8, 2002, to the Audit Committee, our independent auditors confirmed that they are independent accountants with respect to us within the meaning of the Securities Act and the requirements of the Independence Standards Board. The Audit Committee, composed solely of outside directors, meets periodically with the internal auditors and independent auditors (as well as management) to review the work of each. The internal auditors and independent auditors have free access to the Audit Committee, without management present, to discuss the results of their audit work. Management believes that our systems, policies and procedures provide reasonable assurance that operations are conducted in conformity with the law and with management's commitment to a high standard of business conduct. William J. Post Chris N. Froggatt Chairman and Vice President and Controller Chief Executive Officer 29 INDEPENDENT AUDITORS' REPORT To the Stockholder of Arizona Public Service Company Phoenix, Arizona We have audited the accompanying balance sheets of Arizona Public Service Company as of December 31, 2001 and 2000, and the related statements of income, changes in common stock equity and cash flows for each of the three years in the period ended December 31, 2001. Our audits also included the financial statement schedule listed in the accompanying Index. These financial statements and the financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such financial statements present fairly, in all material respects, the financial position of Arizona Public Service Company at December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. As discussed in Note 16 of the financial statements, in 2001 Arizona Public Service Company changed its method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona February 8, 2002 (March 22, 2002, as to Note 17 and February 24, 2003, as to Note 18) 30 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, ----------------------------------------- 2001 2000 1999 ----------- ----------- ----------- (DOLLARS IN THOUSANDS) Electric Operating Revenues Electric retail segment ........................... $ 2,562,088 $ 2,538,750 $ 1,914,722 Marketing and trading segment ..................... 549,240 395,392 154,126 ----------- ----------- ----------- Total ........................................... 3,111,328 2,934,142 2,068,848 ----------- ----------- ----------- Purchased Power and Fuel Costs: Electric retail segment ........................... 1,227,188 1,065,596 432,844 Marketing and trading segment ..................... 313,991 267,032 136,522 ----------- ----------- ----------- Total ........................................... 1,541,179 1,332,628 569,366 ----------- ----------- ----------- Operating Revenues less Purchased Power and Fuel Costs ..................................... 1,570,149 1,601,514 1,499,482 ----------- ----------- ----------- Other Operating Expenses: Operations and maintenance ........................ 465,561 430,092 437,125 Depreciation and amortization ..................... 420,893 425,479 416,331 Income taxes (Note 4) ............................. 183,640 199,977 165,629 Other taxes ....................................... 101,077 99,730 96,579 ----------- ----------- ----------- Total ........................................... 1,171,171 1,155,278 1,115,664 ----------- ----------- ----------- Operating Income ..................................... 398,978 446,236 383,818 Other Income (Deductions): Income taxes ...................................... 504 4,312 32,614 Other income ...................................... 20,207 9,690 13,861 Other expense ..................................... (20,790) (20,547) (25,618) ----------- ----------- ----------- Total ........................................... (79) (6,545) 20,857 ----------- ----------- ----------- Income Before Interest Deductions .................... 398,899 439,691 404,675 ----------- ----------- ----------- Interest Deductions: Interest on long-term debt ........................ 126,118 134,431 132,676 Interest on short-term borrowings ................. 4,407 7,455 8,272 Debt discount, premium and expense ................ 2,650 2,105 2,084 Capitalized interest .............................. (14,964) (10,894) (6,679) ----------- ----------- ----------- Total ........................................... 118,211 133,097 136,353 ----------- ----------- ----------- Income Before Extraordinary Charge and Cumulative Effect Adjustment ................................. 280,688 306,594 268,322 Extraordinary Charge - net of income taxes of $94,115 (Note 1) ............................... -- -- (139,885) Cumulative Effect of Change in Accounting for Derivatives - net of income taxes of $9,892 ............................................ (15,201) -- -- ----------- ----------- ----------- Net Income ........................................... 265,487 306,594 128,437 Preferred Stock Dividend Requirements ................ -- -- 1,016 ----------- ----------- ----------- Earnings for Common Stock ............................ $ 265,487 $ 306,594 $ 127,421 =========== =========== ===========
See Notes to Financial Statements. 31 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS ASSETS
DECEMBER 31, -------------------------- 2001 2000 ----------- ----------- (DOLLARS IN THOUSANDS) Utility Plant (Notes 1, 8 and 9): Electric plant in service and held for future use ........... $ 8,105,106 $ 7,805,025 Less accumulated depreciation and amortization .............. 3,374,098 3,187,328 ----------- ----------- Total ................................................ 4,731,008 4,617,697 Construction work in progress ............................... 321,305 245,749 Nuclear fuel, net of accumulated amortization of $56,836 and $61,836 ............................................... 49,282 47,389 ----------- ----------- Utility Plant -- net ...................................... 5,101,595 4,910,835 ----------- ----------- Investments and Other Assets Decommissioning trust accounts (Note 11) .................... 202,036 204,716 Assets from risk management and trading activities - long-term (Note 16) ....................................... 2,082 32,955 Other assets ................................................ 76,322 45,841 ----------- ----------- Total Investments and Other Assets ................... 280,440 283,512 ----------- ----------- Current Assets: Cash and cash equivalents ................................... 16,821 2,609 Accounts receivable: Service customers ......................................... 182,749 422,012 Other ..................................................... 153,988 48,711 Allowance for doubtful accounts ........................... (3,349) (2,380) Accrued utility revenues .................................... 76,131 74,566 Materials and supplies (at average cost) .................... 81,215 71,966 Fossil fuel (at average cost) ............................... 27,023 19,405 Deferred income taxes (Note 4) .............................. -- 5,793 Assets from risk management and trading activities (Note 16) ................................................. 10,097 17,506 Other ....................................................... 42,009 38,414 ----------- ----------- Total Current Assets ................................. 586,684 698,602 ----------- ----------- Deferred Debits: Regulatory assets (Notes 1 and 3) ........................... 342,383 469,867 Unamortized debt issue costs ................................ 13,163 12,805 Other ....................................................... 42,789 37,928 ----------- ----------- Total Deferred Debits ................................ 398,335 520,600 ----------- ----------- Total Assets ................................................... $ 6,367,054 $ 6,413,549 =========== ===========
See Notes to Financial Statements. 32 ARIZONA PUBLIC SERVICE COMPANY BALANCE SHEETS LIABILITIES AND EQUITY
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 ........................................... 790,289 694,802 Accumulated other comprehensive loss ........................ (64,565) -- ----------- ----------- Common stock equity ....................................... 2,150,690 2,119,768 Long-term debt less current maturities (Note 6) ............. 1,949,074 1,806,908 ----------- ----------- Total Capitalization ................................. 4,099,764 3,926,676 ----------- ----------- Current Liabilities: Commercial paper (Note 5) ................................... 171,162 82,100 Current maturities of long-term debt (Note 6) ............... 125,451 250,266 Accounts payable ............................................ 98,959 267,999 Accrued taxes ............................................... 107,595 106,515 Accrued interest ............................................ 41,043 39,488 Customer deposits ........................................... 28,664 24,498 Deferred income taxes (Note 4) .............................. 3,244 -- Liabilities from risk management and trading activities (Note 16) ................................................. 21,840 37,179 Other ....................................................... 117,770 104,947 ----------- ----------- Total Current Liabilities ............................ 715,728 912,992 ----------- ----------- Deferred Credits and Other: Deferred income taxes (Note 4) .............................. 1,023,079 1,110,437 Deferred investment tax credit (Note 4) ..................... 4,306 4,570 Liabilities from risk management and trading activities - long term (Note 16) ....................................... 95,159 14,711 Unamortized gain -- sale of utility plant (Note 8) .......... 64,060 68,636 Customer advances for construction .......................... 69,293 40,694 Other ....................................................... 295,665 334,833 ----------- ----------- Total Deferred Credits and Other ..................... 1,551,562 1,573,881 ----------- ----------- Commitments and Contingencies (Notes 3, 10, and 11) Total Liabilities and Equity ................................... $ 6,367,054 $ 6,413,549 =========== ===========
See Notes to Financial Statements. 33 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, ----------------------------------- 2001 2000 1999 --------- --------- --------- (DOLLARS IN THOUSANDS) Cash Flows from Operations: Net income ............................................ $ 265,487 $ 306,594 $ 128,437 Items not requiring cash: Depreciation and amortization ....................... 420,893 425,479 416,331 Nuclear fuel amortization ........................... 28,362 30,083 31,371 Deferred income taxes - net ......................... (26,252) (65,457) (56,127) Deferred investment tax credit - net ................ (264) (269) (27,626) Mark-to-market gains - trading ...................... (91,978) (11,752) (975) Mark-to-market gains - system ....................... (8,052) -- -- Extraordinary Charge - net of income taxes .......... -- -- 139,885 Cumulative effect of change in accounting - net of income taxes .................. 15,201 -- -- Changes in certain current assets and liabilities: Accounts receivable - net ........................... 226,933 (232,493) (8,363) Accrued utility revenues ............................ (1,565) (1,647) (5,179) Materials, supplies and fossil fuel ................. (16,867) 475 (8,794) Other current assets ................................ (3,595) (25,035) (4,190) Accounts payable .................................... (190,141) 101,558 22,992 Accrued taxes ....................................... 1,080 43,657 3,031 Accrued interest .................................... 1,555 7,189 1,081 Other current liabilities ........................... 16,989 124,473 6,833 Increase in regulatory assets ......................... (17,516) (14,138) (12,262) Other - net ........................................... (13,164) 34,954 1,514 --------- --------- --------- Net cash provided ................................... 607,106 723,671 627,959 --------- --------- --------- Cash Flows from Investing: Capital expenditures .................................. (467,391) (464,368) (322,547) Capitalized interest .................................. (14,964) (10,894) (6,679) Other ................................................. (41,926) (72,189) (8,173) --------- --------- --------- Net cash used ....................................... (524,281) (547,451) (337,399) --------- --------- --------- Cash Flows from Financing: Issuance of long-term debt ............................ 396,072 300,000 392,952 Short-term borrowings - net ........................... 89,062 43,800 (140,530) Common equity infusion from parent .................... -- -- 50,000 Dividends paid on common stock ........................ (170,000) (170,000) (170,000) Dividends paid on preferred stock ..................... -- -- (1,393) Repayment of preferred stock .......................... -- -- (96,499) Repayment and reacquisition of long-term debt ......... (383,747) (354,888) (323,171) --------- --------- --------- Net cash used ....................................... (68,613) (181,088) (288,641) --------- --------- --------- Net increase (decrease) in cash and cash equivalents ..... 14,212 (4,868) 1,919 Cash and cash equivalents at beginning of year ........... 2,609 7,477 5,558 --------- --------- --------- Cash and cash equivalents at end of year ................. $ 16,821 $ 2,609 $ 7,477 ========= ========= ========= Supplemental disclosure of cash flow information: Cash paid during the year for: Interest (excluding capitalized interest) ........... $ 114,094 $ 123,895 $ 132,995 Income taxes ........................................ $ 212,989 $ 222,866 $ 189,002
See Notes to Financial Statements. 34 ARIZONA PUBLIC SERVICE COMPANY STATEMENTS OF CHANGES IN COMMON STOCK EQUITY For the Years Ended December 31, 1999, 2000 and 2001 (dollars in thousands)
Additional Accumulated Other Common Preferred Paid-in Retained Comprehensive Stock Stock Capital Earnings Income (Loss) Total ----------- ----------- ----------- ----------- ------------- ----------- Balance at December 31, 1998 $ 178,162 $ 95,241 $ 1,195,625 $ 601,968 $ -- $ 2,070,996 Net income 128,437 128,437 Redemption of preferred stock (95,241) (95,241) Preferred stock dividend requirements (1,016) (1,016) Dividends on common stock (170,000) (170,000) Common equity infusion from parent 50,000 50,000 Other 1,179 (1,181) (2) ----------- ----------- ----------- ----------- ----------- ----------- Balance at December 31, 1999 178,162 -- 1,246,804 558,208 -- 1,983,174 Net income 306,594 306,594 Dividends on common stock (170,000) (170,000) ----------- ----------- ----------- ----------- ----------- ----------- Balance at December 31, 2000 178,162 -- 1,246,804 694,802 -- 2,119,768 ----------- ----------- ----------- ----------- ----------- ----------- Net income 265,487 265,487 Minimum pension liability, net of $634 tax effect (966) (966) Cumulative effect of change in accounting for derivatives, net of $47,404 tax effect 72,274 72,274 Unrealized loss on derivative instruments, net of $54,028 tax effect (82,373) (82,373) Reclassification of net realized gain to income, net of $35,091 tax effect (53,500) (53,500) ----------- ----------- ----------- ----------- ----------- ----------- Comprehensive income (loss) 265,487 (64,565) 200,922 ----------- ----------- ----------- ----------- ----------- ----------- Dividends on common stock (170,000) (170,000) ----------- ----------- ----------- ----------- ----------- ----------- Balance at December 31, 2001 $ 178,162 $ -- $ 1,246,804 $ 790,289 $ (64,565) $ 2,150,690 =========== =========== =========== =========== =========== ===========
See Notes to Financial Statements. 35 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES NATURE OF OPERATIONS We are an Arizona electric utility. We are a wholly-owned subsidiary of Pinnacle West Capital Corporation. We provide either retail or wholesale electric service to substantially all of the state of Arizona, with the major exceptions of the Tucson metropolitan area and about one-half of the metropolitan Phoenix area. We also generate and, through Pinnacle West's marketing and trading division, sell and deliver electricity to wholesale customers in the western United States. During 2001, we transferred most of our marketing and trading activities to Pinnacle West, which approximated $219 million in assets and $149 million in liabilities. From time to time, we enter into transactions with Pinnacle West or Pinnacle West's subsidiaries. The following table summarizes the amounts included in the income statements and balance sheets related to transactions with affiliated companies (dollars in millions): For the year ended December 31, ------------------ 2001 2000 1999 ---- ---- ---- Electric operating revenues: Pinnacle West - marketing and trading $ 50 $ -- $ -- APSES 15 26 -- ---- ---- ---- Total $ 65 $ 26 $ -- ==== ==== ==== Purchased power and fuel costs: Pinnacle West - marketing and trading $ 50 $ -- $ -- Pinnacle West Energy 14 -- -- ---- ---- ---- Total $ 64 $ -- $ -- ==== ==== ==== As of December 31, ----------- 2001 2000 ---- ---- Accounts receivable - other: Pinnacle West - marketing and trading $ 76 $ 10 Pinnacle West 24 14 APSES 13 1 Pinnacle West Energy 2 -- ---- ---- Total $115 $ 25 ==== ==== Accounts payable: Pinnacle West - marketing and trading $ 21 $ 1 Pinnacle West Energy 2 1 ---- ---- Total $ 23 $ 2 ==== ==== 36 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Electric revenues include sales of electricity to affiliated companies at contract prices. Purchased power includes purchases of electricity from affiliated companies at contract prices. Intercompany receivables primarily include the amounts related to the transfer of marketing and trading activities discussed above and intercompany sales of electricity. Intercompany payables primarily include amounts related to the purchase of electricity. ACCOUNTING RECORDS AND USE OF ESTIMATES Our accounting records are maintained in accordance with accounting principles generally accepted in the United States of America (GAAP). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. We have reclassified certain prior year amounts to conform to current year presentation. 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 and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. In addition, subject to specified risk parameters established by the Pinnacle West Board of Directors and monitored by Pinnacle West's ERMC, we engage in trading activities intended to profit from market price movements. If a contract was entered into for trading purposes, we account for it in accordance with EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." EITF 98-10 requires energy trading contracts to be measured at fair value as of the balance sheet date with unrealized gains and losses included in earnings on a current basis (the mark-to-market method). See "Mark-to-Market Method" below and Note 16 and Note 18 for further information about our trading contracts. We examine contracts at inception to determine the appropriate accounting treatment. If a contract is not considered energy trading we must determine if it is a derivative as defined in SFAS No. 133 (see Note 16 for further information on SFAS No. 133). If a contract does not meet the derivative criteria or if it qualifies for a SFAS No. 133 scope exception, we account for the contract using accrual accounting (this means that costs and revenues are recorded when physical delivery occurs). For contracts that qualify as a derivative and do not meet a SFAS No. 133 scope exception, we further examine the contract to determine if it will qualify for hedge accounting. If a contract 37 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS does not meet the hedging criteria in SFAS No. 133, we recognize the changes in the fair value of the derivative instrument in income each period (mark-to-market). If it does qualify for hedge accounting, changes in the fair value are recognized as either an asset, as a liability or in stockholder's equity (as a component of accumulated other comprehensive income) depending on the nature of the hedge. Gains and losses related to derivatives that qualify as cash flow hedges of expected transactions are recognized in revenue or fuel and purchased power expense as an offset to the related item being hedged when the underlying hedged physical transaction impacts earnings (deferral method). See Note 16 for further discussion on derivative accounting. MARK-TO-MARKET METHOD Under mark-to-market accounting the purchase or sale of energy commodities are reflected at fair market value, net of reserves, with resulting unrealized gains and losses recorded as assets and liabilities from risk management and trading activities in the balance sheets. We determine fair market value using actively-quoted prices when available. We consider quotes for exchange-traded contracts and over-the-counter quotes obtained from independent brokers to be actively-quoted. When actively-quoted prices are not available, we use prices provided by other external sources. This includes quarterly and calendar year quotes from independent brokers. We shape quarterly and calendar year quotes into monthly prices based on historical relationships. For options, long-term contracts and other contracts where price quotes are not available, we use models and other valuation methods. For illiquid or unquoted market locations, we consider the historical relationship to readily-available market quotations. The valuation models we employ utilize spot prices, forward prices, historical market data and other factors to forecast future prices. For non-exchange traded contracts, we calculate fair market value based on the average of the bid and offer price, and we discount to reflect net present value. We maintain certain reserves for a number of risks associated with the valuation of future commitments. These include reserves for liquidity and credit risks based on the financial condition of counterparties. The liquidity reserve represents the cost that would be incurred if all unmatched positions were closed-out or hedged. As we mark positions to a mid-market value this reserve adjusts the mid-market valuation to the bid or offer, after taking into consideration offsetting positions, to reflect the true cash flow that would be realized upon exiting the net position. A credit reserve is also recorded to represent estimated credit losses on our overall exposure to counterparties, taking into account netting arrangements; expected default experience for the credit rating of the counterparties; and the overall diversification of the portfolio. Counterparties in the portfolio consist principally of major energy companies, municipalities, 38 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS and local distribution companies. We maintain credit policies that management believes minimize overall credit risk. Determination of the credit quality of counterparties is based upon a number of factors, including credit ratings, financial condition, project economics and collateral requirements. When applicable, we employ standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. The use of models and other valuation methods to determine fair market value often requires subjective and complex judgment. Actual results could differ from the results estimated through application of these methods. However, essentially all of our marketing and trading activities are structured activities. This means our portfolio of forward sales positions is substantially hedged with a portfolio of forward purchases that protects the economic value of the sales transactions. Our practice is to hedge within timeframes established by the Pinnacle West ERMC. REGULATORY ACCOUNTING We are regulated by the ACC and the FERC. The accompanying financial statements reflect the rate-making 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 3 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 3), the ACC accelerated the amortization of substantially all of our regulatory assets to an eight-year period that would have ended June 30, 2004. The regulatory assets to be recovered under the 1999 Settlement Agreement are currently being amortized as follows (dollars in millions): 39 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 1/1 - 6/30 1999 2000 2001 2002 2003 2004 Total ------ ------ ------ ------ ------ ------ ------ $ 164 $ 158 $ 145 $ 115 $ 86 $ 18 $ 686 Regulatory assets are reported as deferred debits on the balance sheets. As of December 31, 2001 and 2000, they are comprised of the following (dollars in millions): December 31, -------------------- 2001 2000 -------- -------- Remaining balance recoverable under the 1999 Settlement Agreement (a) $ 219 $ 364 Spent fuel storage (Note 10) 43 40 Electric industry restructuring transition costs (Note 3) 34 24 Other 46 42 -------- -------- Total regulatory assets $ 342 $ 470 ======== ======== (a) The majority of our unamortized regulatory assets above relates to deferred income taxes (see Note 4) and rate synchronization cost deferrals (see "Rate Synchronization Cost Deferrals" below). Regulatory liabilities are included in deferred credits on the balance sheets and as of December 31, 2001 and 2000 are comprised of the following (dollars in millions): December 31, -------------------- 2001 2000 -------- -------- Deferred gains on utility property $ 20 $ 20 Other 7 8 -------- -------- Total regulatory liabilities $ 27 $ 28 ======== ======== The balance sheets include the amounts listed below for generation assets not subject to SFAS No. 71 as of December 31, 2001 and 2000 (dollars in millions): December 31, -------------------- 2001 2000 -------- -------- Electric plant in service and held for future use ...... $ 3,878 $ 3,854 Accumulated depreciation and amortization .............. (1,990) (1,902) Construction work in progress .......................... 119 86 Nuclear fuel, net of amortization ...................... 49 47 40 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS As a result of our 1999 Settlement Agreement, we plan to move our generation assets and activities to Pinnacle West Energy no later than December 31, 2002. Following the transfer, our financial statements would no longer include generation assets and activities. Our preliminary estimate of the net assets (the generation assets described above and the related liabilities) that would be transferred is approximately $850 million based on book values at December 31, 2001. We have requested that the ACC approve a purchase power agreement and a proposed rule variance related to our power procurement after the transfer. This request is currently pending ACC consideration (see Note 3). The specific impacts of the generation transfer on our revenues and expenses are not yet determinable pending the outcome of the ACC proceedings. In addition, as of December 31, 2001, we completed the transition of our marketing and trading activities to the parent. In 2001, we recorded the following pretax amounts related to marketing and trading activities: $549 million of electric revenues and $314 million of purchased power and fuel costs. UTILITY PLANT AND DEPRECIATION Utility plant is the term we use to describe the business property and equipment that supports electric service, consisting primarily of generation, transmission, and distribution facilities. We report utility plant at our original cost, which includes: * material and labor; * contractor costs; * construction overhead costs (where applicable); and * capitalized interest or an allowance for funds used during construction. We charge retired utility plant, plus removal costs less salvage realized, to accumulated depreciation. See Note 2 for information on a new accounting standard that impacts accounting for removal costs. We record depreciation on utility property on a straight-line basis. For the years 1999 through 2001 the rates, as prescribed by our regulators, ranged from a low of 1.49% to a high of 20%. The weighted-average rate was 3.40% for 2001, 3.40% for 2000, and 3.34% for 1999. We depreciate non-utility property and equipment over the estimated useful lives of the related assets, ranging from 3 to 30 years. We expense the costs of plant outages, major maintenance and routine maintenance as incurred. CAPITALIZED INTEREST Capitalized interest represents the cost of debt funds used to finance construction of utility plants. Plant construction costs, including capitalized interest, are expensed through depreciation when completed projects are placed into commercial operation. Capitalized interest does not represent current cash earnings. The rate used to calculate capitalized interest was a composite rate of 6.26% for 2001, 6.62% for 2000, and 6.65% for 1999. 41 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS REVENUES We record electric operating revenues on the accrual basis, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. We exclude sales taxes on electric revenues from both revenue and taxes other than income taxes. Other than revenues and purchased power costs related to energy trading activities, revenues are recorded on a gross basis in our income statements. See Note 18 for information related to a change in presentation of certain marketing and trading revenues to a net basis. CASH AND CASH EQUIVALENTS For purposes of the statement of cash flows, we consider all highly liquid debt instruments purchased with an initial maturity of three months or less to be cash equivalents. RATE SYNCHRONIZATION COST DEFERRALS As authorized by the ACC, operating costs (excluding fuel) and financing costs of Palo Verde Units 2 and 3 were deferred from the commercial operation dates (September 1986 for Unit 2 and January 1988 for Unit 3) until the date the units were included in a rate order (April 1988 for Unit 2 and December 1991 for Unit 3). In accordance with the 1999 Settlement Agreement, we are continuing to accelerate the amortization of the deferrals over an eight-year period that will end June 30, 2004. Amortization of the deferrals is included in depreciation and amortization expense in the statements of income. NUCLEAR FUEL We charge nuclear fuel to fuel expense by using the unit-of-production method. The unit-of-production method is an amortization method that is based on actual physical usage. We divide the cost of the fuel by the estimated number of thermal units that we expect to produce with that fuel. We then multiply that rate by the number of thermal units that we produce within the current period. This calculation determines the current period nuclear fuel expense. We also charge nuclear fuel expense for the permanent disposal of spent nuclear fuel. The United States Department of Energy (DOE) is responsible for the permanent disposal of spent nuclear fuel, and it charges us $0.001 per kWh of nuclear generation. See Note 10 for information about spent nuclear fuel disposal and Note 11 for information on nuclear decommissioning costs. 42 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS REACQUIRED DEBT COSTS For debt related to the regulated portion of our business, we amortize those gains and losses incurred upon early retirement over the remaining life of the debt. In accordance with the 1999 Settlement Agreement, we are continuing to accelerate reacquired debt costs over an eight-year period that will end June 30, 2004. The accelerated portion of the regulatory asset amortization is included in depreciation and amortization expense in the statements of income. 2. 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." This standard is effective for the year beginning January 1, 2002. We have no goodwill recorded in our balance sheets. The impacts of this new standard are not material to our financial statements. 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. 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. This standard does not impact our financial statements at adoption. In 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), "Accounting for Certain Costs Related to Property, Plant, and Equipment." This proposed SOP would create a project timeline framework for capitalizing costs related to property, plant and equipment (PP&E) construction, require that PP&E assets be accounted for at the component level, and require administrative and general costs incurred in support of capital projects to be expensed in the current period. The AICPA plans to issue the final SOP in the fourth quarter of 2002. In 1986, we entered into agreements with three separate special purpose entity (SPE) lessors in order to sell and lease back interests in Palo Verde Unit 2 (see Note 8). The leases are accounted for as operating leases in accordance with GAAP. In February 2002, the FASB discussed issues related to special purpose entities. It is expected that FASB will issue additional guidance on accounting for SPEs later this year. As a result of future FASB actions, we may be required to consolidate the SPEs in our financial statements. If consolidation is required, the assets and liabilities of the SPEs that relate to the sale-leaseback transactions would be reflected on our balance sheets. The 43 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS SPE debt that is not reflected on our balance sheets is approximately $300 million at December 31, 2001. Rating agencies have already considered this debt when evaluating our credit ratings. 3. REGULATORY MATTERS ELECTRIC INDUSTRY RESTRUCTURING STATE 1999 SETTLEMENT AGREEMENT. On May 14, 1999, we entered into a comprehensive 1999 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 single issue of whether the ACC could itself become a party to the 1999 Settlement Agreement by virtue of its approval of the 1999 Settlement Agreement. On December 14, 2001, the Arizona Supreme Court vacated its own October 5, 2001 order accepting jurisdiction and decided to dismiss the appeal. As a result, the judicial challenges to the 1999 Settlement Agreement have terminated. Consistent with our obligations under the 1999 Settlement Agreement, on January 7, 2002, we and the ACC filed in Maricopa County, Arizona Superior Court a stipulation to dismiss all of our litigation pending against the ACC. On January 15, 2002, a Maricopa County Superior Court judge issued an order dismissing such litigation. The following are the major provisions of the 1999 Settlement Agreement, as approved: * 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 44 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 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 we 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 opportunity to recover $350 million net present value through a competitive transition charge that will remain in effect through 45 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 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 competitive electric assets and 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, although the ACC's recent establishment of a "generic" docket to consider electric industry restructuring in Arizona and the consolidation of that docket with our request for approval of a PPA between Pinnacle West and us could affect our ability to transfer assets to Pinnacle West Energy. 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. As discussed in Note 1 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 marketing and trading 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: * grant us a partial variance from an ACC rule that would obligate us to acquire all of our customers' standard-offer, full-service generation requirements from the competitive market (with at least 50% of those requirements coming from a "competitive bidding" process) starting in 2003; and * 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 ongoing reliable service to our standard-offer, full-service 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. 46 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS * 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 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 us 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) the FERC's acceptance of the PPA and the companion agreement between Pinnacle West and Pinnacle West Energy. We are required to transfer our competitive electric assets and services to one or more corporate affiliates on or before December 31, 2002. Consistent with that requirement, we have been addressing the legal and regulatory requirements necessary to complete the transfer of our generation assets to Pinnacle West Energy on or before that date. In anticipation of our transfer of generation assets, Pinnacle West Energy has completed, and is in the process of developing and planning, various generation expansion projects so that we can reliably meet 47 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS the energy requirements of our Arizona customers. See Note 1 for information relating to our pending transfer of generation assets and associated liabilities to Pinnacle West Energy. By letter dated January 14, 2002, the Chairman of the ACC stated that "the [ACC's] Electric Competition Rules, along with the Settlement Agreements approved for us and [Tucson Electric Company], establish the framework for the transition to a retail generation competitive market." The ACC Chairman then recommended that the ACC establish a new "generic" docket to "determine if changed circumstances require the [ACC] to take another look at electric restructuring in Arizona." Matters that would be addressed by the ACC in the new docket would include: * whether the ACC should continue implementation of the retail electric competition Rules adopted by the ACC in 1999 in their current form or with modifications; * whether the ACC should "slow the pace of the implementation of the [Rules] to provide an opportunity to consider the extent to which [Rule] modification and variance is in the public interest, including changing the direction to retail electric competition"; and * whether the ACC should "step back from electric industry restructuring until the [ACC] is convinced that there exists a viable competitive wholesale electric market to support retail electric competition in Arizona." On January 22, 2002 the ACC's Chief ALJ issued a procedural order by which a generic docket was opened. On February 8, 2002, the ACC's ALJ issued a procedural order which consolidated the ACC docket relating to our October 2001 filing with several other pending ACC dockets, including the generic docket. Although the order consolidates several dockets, it states that a hearing on our matter will commence on April 29, 2002. The order went on to state that, contrary to our position, the ALJ was construing the October 2001 filing as a request by us to amend the ACC order that approved the 1999 Settlement Agreement. On March 22, 2002, the ACC Staff issued a report to the ACC recommending that the ACC address the following issues in the generic docket: * The extent and manner of the ACC's involvement in monitoring market conditions and/or mitigating the development of market power for generation and transmission; * The lack of guidance in the Rules regarding the mechanics of the "competitive bidding process" referenced above; * The consideration of alternatives to the transfer of generation assets required by the Rules (the ACC Staff stated that such transfers would be "unwise" at the present time and recommended that "all transfer and 48 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS separation of utilities' assets be stayed pending the completion of the generic docket"); * The consideration of transmission constraints that could impact the development of the wholesale power market; * The reassessment of adjustor mechanisms for standard-offer rates in light of problems with the development of a wholesale power market; and * The adequacy of customer "shopping credits" in the context of the development of a competitive retail market (a shopping credit is the cost a customer does not pay to a utility distribution company if the customer obtains generation from another party). Although not a specific ACC Staff recommendation, the report was also critical of certain aspects of the proposed purchase power agreement between the Company and Pinnacle West. A modification to the competition Rules or the 1999 Settlement Agreement could, among other things, adversely affect our ability to transfer our generation assets to Pinnacle West Energy by December 31, 2002. We cannot predict the outcome of the consolidated docket or its effect on the specific requests in our October 2001 filing, the existing Arizona electric competition rules, or the 1999 Settlement Agreement. 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 has been dismissed. 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 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 49 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 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 noncompetitive 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 electric assets and services either to an unaffiliated party or to a separate corporate affiliate. Under the 1999 Settlement Agreement, we received a waiver to allow transfer of our competitive electric 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, although the ACC's recent establishment of a "generic" docket to consider electric industry restructuring in Arizona and the consolidation of that docket with our request for approval of a PPA between Pinnacle West and us could affect our ability to transfer assets to Pinnacle West Energy (see "Proposed Rule Variance and Purchase Power Agreement" above). 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, full-service customers under rates that have been approved by the ACC. These rates are established until July 1, 2004. The 1999 Settlement Agreement allows us to seek adjustment of these rates in the event of emergency conditions or circumstances, such as the inability to secure financing 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. Energy prices in the western wholesale market vary and, during the course of the last two years, have been volatile. At various times, prices in the spot wholesale market have significantly exceeded the amount included in our current retail rates. In the 50 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 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. 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 51 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS competitive generation services), and thereafter for all customers receiving competitive electric generation. GENERAL We cannot accurately predict the impact of full retail competition on our financial position, cash flows, results of operations, or liquidity. As competition in the electric industry continues to evolve, we will continue to evaluate strategies and alternatives that will position us to compete in the new regulatory environment. FEDERAL In June 2001, the 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. We cannot accurately predict the overall financial impact of the plan on the various aspects of our business, including our wholesale and purchased power activities. 4. INCOME TAXES INCOME TAXES We are included in Pinnacle West's consolidated tax return. However, when Pinnacle West allocates income taxes to us, it does so based on our taxable income or loss alone. Because of a 1994 rate settlement agreement, we accelerated amortization of substantially all of our ITCs over a five-year period (1995-1999). Certain assets and liabilities are reported differently for income tax purposes than they are for financial statements. The tax effect of these differences is recorded as deferred taxes. We calculate deferred taxes using the current income tax rates. We have recorded a regulatory asset related to income taxes on our balance sheets in accordance with SFAS No. 71. This regulatory asset is for certain temporary differences, primarily the allowance for equity funds used during construction. We amortize this amount as the differences reverse. In accordance with the 1999 Settlement Agreement, we are continuing to accelerate our amortization of the regulatory asset for income taxes over an eight-year period that will end June 30, 2004 (see Note 1). We are including this accelerated amortization in depreciation and amortization expense on the Statements of Income. The components of income tax expense for income before extraordinary charge and cumulative effect adjustment are (dollars in thousands): 52 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Year Ended December 31, -------------------------------------- 2001 2000 1999 ---------- ---------- ---------- Current Federal $ 174,251 $ 211,139 $ 175,227 State 35,401 50,252 41,541 ---------- ---------- ---------- Total current 209,652 261,391 216,768 Deferred (26,252) (65,457) (56,127) ITC amortization (264) (269) (27,626) ---------- ---------- ---------- Total expense $ 183,136 $ 195,665 $ 133,015 ========== ========== ========== The following chart compares pretax income at the 35% federal income tax rate to income tax expense (dollars in thousands): Year Ended December 31, -------------------------------------- 2001 2000 1999 ---------- ---------- ---------- Federal income tax expense at 35% statutory rate $ 162,338 $ 175,791 $ 140,444 Increases (reductions) in tax expense resulting from: ITC amortization (264) (269) (27,626) State income tax net of federal income tax benefit 20,563 20,007 20,699 Other 499 136 (502) ---------- ---------- ---------- Income tax expense $ 183,136 $ 195,665 $ 133,015 ========== ========== ========== 53 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS The components of the net deferred income tax liability were as follows (dollars in thousands): December 31, ------------------------- 2001 2000 ---------- ---------- DEFERRED TAX ASSETS Deferred gain on Palo Verde Unit 2 sale/leaseback $ 25,374 $ 27,056 Risk management and trading activities 46,343 15,002 Other 111,318 126,909 ---------- ---------- Total deferred tax assets 183,035 168,967 ---------- ---------- DEFERRED TAX LIABILITIES Plant-related 1,069,207 1,081,637 Regulatory asset for income taxes 121,757 172,082 Risk management and trading activities 18,394 19,892 ---------- ---------- Total deferred tax liabilities 1,209,358 1,273,611 ---------- ---------- Accumulated deferred income taxes - net $1,026,323 $1,104,644 ========== ========== 5. LINES OF CREDIT We had committed lines of credit with various banks of $250 million at December 31, 2001 and 2000, which were available either to support the issuance of commercial paper or to be used for bank borrowings. The commitment fees at December 31, 2001 and 2000 for these lines of credit were 0.09% per annum. We had no bank borrowings outstanding under these lines of credit at December 31, 2001 and 2000. Our commercial paper borrowings outstanding were $171 million at December 31, 2001 and $82 million at December 31, 2000. The weighted average interest rate on commercial paper borrowings was 4.72% for the year ended December 31, 2001 and 6.64% for the year ended December 31, 2000. By Arizona statute, our short-term borrowings cannot exceed 7% of our total capitalization unless approved by the ACC. 6. LONG-TERM DEBT Borrowings under our mortgage bond indenture are secured by substantially all utility plant. We also have unsecured debt. The following table presents the components of long-term debt outstanding at December 31, 2001 and 2000 (dollars in thousands): 54 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS December 31, ----------------------- Maturity Interest Dates (a) Rates 2001 2000 --------- ---------- ---------- ---------- First mortgage bonds 2002 8.125% $ 125,000 $ 125,000 2004 6.625% 80,000 80,000 2021 9.5% -- 45,140 2021 9.0% -- 72,370 2023 7.25% 54,150 70,650 2024 8.75% 121,668 121,668 2025 8.0% 33,075 33,075 2028 5.5% 25,000 25,000 2028 5.875% 154,000 154,000 Unamortized discount and premium (5,266) (5,993) Pollution control bonds 2024-2034 Adjustable rate(b) 386,860 476,860 Pollution control bonds 2029 3.30%(c) 90,000 -- Unsecured notes 2004 5.875% 125,000 125,000 Unsecured notes 2005 6.25% 100,000 100,000 Unsecured notes 2005 7.625% 300,000 300,000 Unsecured notes 2011 6.375% 400,000 -- Floating rate notes 2001 Adjustable rate(d) -- 250,000 Senior notes (e) 2006 6.75% 83,695 83,695 Capitalized lease obligation 2001-2003 7.75% 417 709 Capitalized lease obligation 2006 5.89% 926 -- ---------- ---------- Total long-term debt 2,074,525 2,057,174 Less current maturities 125,451 250,266 ---------- ---------- Total long-term debt less current maturities $1,949,074 $1,806,908 ========== ========== (a) This schedule does not reflect the timing of redemptions that may occur prior to maturity. (b) The weighted-average rate for the year ended December 31, 2001 was 2.55% and for December 31, 2000 was 4.06%. Changes in short-term interest rates would affect the costs associated with this debt. (c) In November 2001 these bonds were converted to a one year fixed rate of 3.30%. These bonds were previously adjustable rate and from January 1, 2001 until October 31, 2001 the weighted average rate was 2.72%. (d) The weighted-average rate for the year ended December 31, 2000 was 7.33%. Interest for 2000 was based on LIBOR + 0.72%. (e) We currently have outstanding $84 million of first mortgage bonds (senior note mortgage bonds) issued to the senior note trustee as collateral for the senior notes. The senior note mortgage bonds have the same interest 55 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS rate, interest payment dates, maturity, and redemption provisions as the senior notes. Our payments of principal, premium, and/or interest on the senior notes satisfy our corresponding payment obligations on the senior note mortgage bonds. As long as the senior note mortgage bonds secure the senior notes, the senior notes will effectively rank equally with the first mortgage bonds. When we repay all of our first mortgage bonds, other than those that secure senior notes, the senior note mortgage bonds will no longer secure the senior notes and will cease to be outstanding. Our bank agreements have financial covenants, including an interest coverage test and a debt ratio. We anticipate that we will be able to meet the covenant requirement levels. The following is a list of principal payments due on total long-term debt and sinking fund requirements through 2006: * $125 million in 2002; * $ 0 million in 2003; * $205 million in 2004; * $400 million in 2005; and * $ 84 million in 2006. Our first mortgage bondholders share a lien on substantially all utility plant assets (other than nuclear fuel and transportation equipment and other excluded assets). The mortgage bond indenture restricts the payment of common stock dividends under certain conditions. These conditions did not exist at December 31, 2001. 7. RETIREMENT PLANS AND OTHER BENEFITS PENSION PLAN Through 1999, we sponsored defined benefit pension plans for our employees. As of January 1, 2000, we are part of a multi-employer plan sponsored by Pinnacle West. In 2001, we represent 89% of the total cost of this plan. A defined benefit plan specifies the amount of benefits a plan participant is to receive using information about the participant. The plan covers nearly all of our employees. Our employees do not contribute to this plan. Generally, the benefits under this plan are calculated based on age, years of service, and pay. Pinnacle West funds the plan by contributing at least the minimum amount required under Internal Revenue Service regulations but no more than the maximum tax-deductible amount. The assets in the plan at December 31, 2001 were mostly domestic and international common stocks and bonds and real estate. 56 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS The following table shows our contributions and pension expense, including administrative costs, and after consideration of amounts capitalized or billed to electric plant participants for 2001, 2000, and 1999 (dollars in millions): 2001 2000 1999 -------- -------- -------- Contributions $ 44 $ 23 $ 25 Pension Expense $ 6 $ 2 $ 4 The following table shows the components of Pinnacle West's consolidated net periodic pension cost before consideration of amounts capitalized or billed to electric plant participants (dollars in thousands):
2001 2000 1999 ---------- ---------- ---------- Service cost - benefits earned during the period $ 26,640 $ 24,955 $ 24,982 Interest cost on projected benefit obligation 62,920 58,361 52,905 Expected return on plan assets (77,340) (77,231) (68,335) Amortization of: Transition asset (3,227) (3,227) (3,226) Prior service cost 2,716 2,078 2,078 Net actuarial gain -- (1,633) -- ---------- ---------- ---------- Net periodic pension cost $ 11,709 $ 3,303 $ 8,404 ========== ========== ==========
The following table shows a reconciliation of the funded status of the plan to the amounts recognized in Pinnacle West's consolidated balance sheets (dollars in thousands): 2001 2000 --------- --------- Funded status - pension plan assets less than projected benefit obligation $(116,213) $ (20,730) Unrecognized net transition asset (13,554) (16,781) Unrecognized prior service cost 24,465 18,558 Unrecognized net actuarial (gains)/losses 94,952 (23,816) --------- --------- Net pension liability recognized in the balance sheets $ (10,350) $ (42,769) ========= ========= 57 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS The following table sets forth the change in projected benefit obligation for Pinnacle West's consolidated defined benefit pension plan for the plan years 2001 and 2000 (dollars in thousands): 2001 2000 ---------- ---------- Projected pension benefit obligation at beginning of year $ 795,926 $ 742,638 Service cost 26,640 24,955 Interest cost 62,920 58,361 Benefit payments (31,647) (30,568) Actuarial losses 18,625 540 Plan amendments 8,622 -- ---------- ---------- Projected pension benefit obligation at end of year $ 881,086 $ 795,926 ========== ========== The following table sets forth Pinnacle West's consolidated defined benefit pension plan's change in the fair value of plan assets for the plan years 2001 and 2000 (dollars in thousands): 2001 2000 ---------- ---------- Fair value of pension plan assets at beginning of year $ 775,196 $ 779,913 Actual gain/(loss) on plan assets (22,876) 1,851 Employer contributions 44,200 24,000 Benefit payments (31,647) (30,568) ---------- ---------- Fair value of pension plan assets at end of year $ 764,873 $ 775,196 ========== ========== Pinnacle West made the assumptions below to calculate the pension liability: 2001 2000 ---------- ---------- Discount rate 7.50% 7.75% Rate of increase in compensation levels 4.00% 4.25% Expected long-term rate of return on assets 10.00% 10.00% 58 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS EMPLOYEE SAVINGS PLAN BENEFITS Through 1999, we sponsored defined contribution savings plans for our employees. As of January 1, 2000, we are part of a multi-employer plan sponsored by Pinnacle West. In 2001, we represent 83% of the total cost of this plan. In a defined contribution plan, the benefits a participant will receive result from regular contributions they make to a participant account. Under this plan, Pinnacle West makes matching contributions in Pinnacle West stock to participant accounts. At December 31, 2001 approximately 30% of total plan assets were in Pinnacle West stock. We recorded expenses for this plan of approximately $4 million for 2001, $3 million for 2000, and $4 million for 1999. POSTRETIREMENT PLAN Through 1999, we sponsored postretirement medical and life insurance plans for our employees. As of January 1, 2000, we are part of a multi-employer plan sponsored by Pinnacle West. In 2001, we represent 93% of the total cost of this plan. We provide medical and life insurance benefits to retired employees. Employees must retire to become eligible for these retirement benefits, which are based on years of service and age. For the medical insurance plans, retirees make contributions to cover a portion of the plan costs. For the life insurance plan, retirees do not make contributions to cover a portion of the plan costs. We retain the right to change or eliminate these benefits. Funding is based upon actuarially determined contributions that take tax consequences into account. Plan assets consist primarily of domestic stocks and bonds. The following table shows our contributions and postretirement benefit expense after consideration of amounts capitalized or billed to electric plant participants for 2001, 2000, and 1999 (dollars in millions): 2001 2000 1999 -------- -------- -------- Contributions $ 11 $ 5 $ 10 Postretirement benefit expense $ 6 $ 2 $ 6 The following table shows the components of Pinnacle West's consolidated net periodic postretirement benefit costs before consideration of amounts capitalized or billed to electric plant participants (dollars in thousands): 59 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
2001 2000 1999 ---------- ---------- ---------- Service cost - benefits earned during the period $ 9,438 $ 8,613 $ 8,939 Interest cost on accumulated benefit obligation 21,585 19,315 17,366 Expected return on plan assets (21,985) (22,381) (18,454) Amortization of: Transition obligation 7,698 7,698 7,698 Net actuarial gains (4,066) (7,983) (5,117) ---------- ---------- ---------- Net periodic postretirement benefit cost $ 12,670 $ 5,262 $ 10,432 ========== ========== ==========
The following table shows a reconciliation of the funded status of the plan to the amounts recognized in Pinnacle West's consolidated balance sheets (dollars in thousands): 2001 2000 ---------- ---------- Funded status - postretirement plan assets less than projected benefit obligation $ (80,544) $ (14,851) Unrecognized net obligation at transition 84,748 92,446 Unrecognized net actuarial gains (8,606) (81,280) ---------- ---------- Net postretirement amount recognized in the balance sheets $ (4,402) $ (3,685) ========== ========== The following table sets forth Pinnacle West's consolidated postretirement benefit plan's change in accumulated benefit obligation for the plan years 2001 and 2000 (dollars in thousands): 2001 2000 ---------- ---------- Accumulated postretirement benefit obligation at beginning of year $ 264,006 $ 231,989 Service cost 9,438 8,613 Interest cost 21,585 19,315 Benefit payments (10,194) (8,905) Actuarial losses 33,520 12,994 ---------- ---------- Accumulated postretirement benefit obligation at end of year $ 318,355 $ 264,006 ========== ========== 60 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS The following table sets forth Pinnacle West's consolidated postretirement benefit plan's change in the fair value of plan assets for the plan years 2001 and 2000 (dollars in thousands): 2001 2000 ---------- ---------- Fair value of postretirement plan assets at beginning of year $ 249,154 $ 257,538 Actual loss on plan assets (12,550) (4,436) Employer contributions 11,400 4,958 Benefit payments (10,194) (8,906) ---------- ---------- Fair value of postretirement plan assets at the end of year $ 237,810 $ 249,154 ========== ========== Pinnacle West made the assumptions below to calculate the postretirement liability: 2001 2000 -------- -------- Discount rate 7.50% 7.75% Expected long-term rate of return on assets - after tax 8.86% 8.77% Initial health care cost trend rate - under age 65 7.00% 7.00% Initial health care cost trend rate - age 65 and over 7.00% 6.00% Ultimate health care cost trend rate 5.00% 5.00% Year ultimate health care trend rate is reached 2006 2002 The following table shows the effect of a 1% increase or decrease in the health care cost trend rate (dollars in millions): 1% increase 1% decrease ----------- ----------- Effect on 2001 cost of postretirement benefits other than pensions $ 6 $ (5) Effect on the accumulated postretirement benefit obligation at December 31, 2001 $ 54 $ (43) 8. LEASES In 1986, we sold about 42% of our share of Palo Verde Unit 2 and certain common facilities in three separate sale leaseback transactions. We account for these leases as operating leases. The gain of approximately $140 million was deferred and is being amortized to operations expense over 29.5 years, the original term of the leases. There are options to renew the leases for two additional years and to purchase the property for fair market value at the end of the lease terms. Consistent with the ratemaking treatment, an amount equal to the annual lease payments is included in rent expense. A regulatory asset is recognized for the difference between lease payments and rent expense calculated on a straight-line basis. See Note 2 for a discussion of special purpose 61 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS entities, including the special purpose entities involved in the Palo Verde sale-leaseback transactions. The average amounts to be paid for the Palo Verde Unit 2 leases are approximately $49 million per year for the years 2002-2015. In accordance with the 1999 Settlement Agreement, we are continuing to accelerate amortization of the regulatory asset for leases over an eight-year period that will end June 30, 2004 (see Note 1). All regulatory asset amortization is included in depreciation and amortization expense in the statements of income. The balance of this regulatory asset at December 31, 2001 was $24 million. In December 2000, we purchased Units 1, 2, and 3 of West Phoenix Power Plant, which was previously leased under a capitalized lease obligation. In addition, we lease certain land, buildings, equipment, and miscellaneous other items through operating rental agreements with varying terms, provisions, and expiration dates. Total lease expense was $52 million in 2001, $53 million in 2000, and $49 million in 1999. Estimated future minimum lease commitments, are approximately $61 million for each of the years 2002 to 2006 and $507 million thereafter. 62 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 9. JOINTLY-OWNED FACILITIES We share ownership of some of our generating and transmission facilities with other companies. The following table shows our interest in those jointly-owned facilities recorded on the balance sheets at December 31, 2001. Our share of operating and maintaining these facilities is included in the income statement in operations and maintenance expense. Each participant is entitled to its share of power generated.
PERCENT CONSTRUCTION OWNED BY PLANT IN ACCUMULATED WORK IN COMPANY SERVICE DEPRECIATION PROGRESS ------- ---------- ------------ --------- (dollars in thousands) Generating Facilities: Palo Verde Nuclear Generating Station Units 1 and 3 29.1% $1,822,369 $(862,880) $ 10,984 Palo Verde Nuclear Generating Station Unit 2 (see Note 8) 17.0% 571,217 (278,234) 46,284 Four Corners Steam Generating Station Units 4 and 5 15.0% 150,298 (78,983) 503 Navajo Steam Generating Station Units 1, 2, and 3 14.0% 235,409 (104,189) 1,044 Cholla Steam Generating Station Common Facilities (a) 62.8%(b) 74,356 (41,555) 1,093 Transmission Facilities: ANPP 500KV System 35.8%(b) 67,911 (24,293) 405 Navajo Southern System 31.4%(b) 27,053 (16,833) 202 Palo Verde-Yuma 500KV System 23.9%(b) 9,685 (4,029) 8 Four Corners Switchyards 27.5%(b) 3,071 (1,945) -- Phoenix-Mead System 17.1%(b) 36,418 (2,766) -- Palo Verde - Estrella 500KV System 50.0%(b) -- -- 2,215
(a) PacifiCorp owns Cholla Unit 4 and we operate the unit for PacifiCorp. The common facilities at the Cholla Plant are jointly-owned. (b) Weighted average of interests. 63 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 10. COMMITMENTS AND CONTINGENCIES ENRON We recorded charges totaling $13 million before income taxes for exposure to Enron and its affiliates in the fourth quarter of 2001. This amount is comprised of a $7 million reserve for the Company's net exposure to Enron and its affiliates, and additional expenses of $6 million primarily related to 2002 power contracts with Enron that were canceled. POWER SERVICE AGREEMENT By letter dated March 7, 2001, Citizens, which owns a utility in Arizona, 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. In addition, in testimony filed with the ACC on March 13, 2002, Citizens acknowledged that, based on its review, "if Citizens filed a complaint with FERC, it probably would lose the central issue in the contract interpretation dispute." We terminated the power service agreement with Citizens 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. PALO VERDE NUCLEAR GENERATING STATION Nuclear power plant operators are required to enter into spent fuel disposal contracts with DOE, and DOE is required to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. Although the Nuclear Waste Act required the DOE to develop a permanent repository for the storage and disposal of spent nuclear fuel by 1998, the DOE has announced that the repository cannot be completed before 2010 and that it does not intend to begin accepting spent fuel prior to that date. In November 1997, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision preventing the DOE from excusing its own delay, but refused to order the DOE to begin accepting spent nuclear fuel. Based on this decision and DOE's delay, a number of utilities filed damages actions against DOE in the Court of Federal Claims. In February 2002 the Secretary of Energy recommended to President Bush that the Yucca Mountain, Nevada site be developed as a permanent repository for spent nuclear fuel. The President transmitted this recommendation to Congress. A congressional decision on this issue is expected sometime during mid-summer 2002. We cannot currently predict what further steps will be taken in this area. We have existing fuel storage pools at Palo Verde and are in the process of completing construction of a new facility for on-site dry storage of spent fuel. With the existing storage pools and the addition of the new facility, we believe 64 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS that spent fuel storage or disposal methods will be available for use by Palo Verde to allow our continued operation through the term of the operating license for each Palo Verde unit. Although some low-level waste has been stored on-site in a low-level waste facility, we are currently shipping low-level waste to off-site facilities. We currently believe that interim low-level waste storage methods are or will be available for use by Palo Verde to allow our continued operation and to safely store low-level waste until a permanent disposal facility is available. We currently estimate that we will incur $407 million (in 2001 dollars) over the life of Palo Verde for our share of the costs related to the on-site interim storage of spent nuclear fuel. As of December 31, 2001, we had recorded a liability and regulatory asset of $43 million for on-site interim nuclear fuel storage costs related to nuclear fuel burned to date. The Palo Verde participants have insurance for public liability 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 interest in the three Palo Verde units, our maximum potential assessment per incident for all three units is approximately $77 million, with an annual payment limitation of approximately $9 million. The Palo Verde participants maintain "all risk" (including nuclear hazards) insurance for property damage to, and decontamination of, property at Palo Verde in the aggregate amount of $2.75 billion, a substantial portion of which must first be applied to stabilization and decontamination. We have also secured insurance against portions of any increased cost of generation or purchased power and business interruption resulting from a sudden and unforeseen outage of any of the three units. The insurance coverage discussed in this and the previous paragraph is subject to certain policy conditions and exclusions. FUEL AND PURCHASED POWER COMMITMENTS We are a party to various fuel and purchased power contracts with terms expiring from 2002 through 2021 that include required purchase provisions. We estimate our contract requirements to be approximately $252 million in 2002, $124 million in 2003, $80 million in 2004, $65 million in 2005 and $68 million in 2006. However, this amount may vary significantly pursuant to certain provisions in such contracts that permit us to decrease our required purchases under certain circumstances. Any purchased power contracts after 2003 will all be recorded on Pinnacle West through their marketing and trading division. 65 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS COAL MINE RECLAMATION OBLIGATIONS We must reimburse certain coal providers for amounts incurred for coal mine reclamation. We estimate our share of the total obligation to be about $103 million. The portion of the coal mine reclamation obligation related to coal already burned is about $59 million at December 31, 2001 and is included in deferred credits-other in the balance sheets. A regulatory asset has been established for amounts not yet recovered from ratepayers related to the coal obligations. In accordance with the 1999 Settlement Agreement with the ACC, we are continuing to accelerate the amortization of the regulatory asset for coal mine reclamation over an eight-year period that will end June 30, 2004. Amortization is included in depreciation and amortization expense on the statements of income. CALIFORNIA ENERGY MARKET ISSUES AND REFUNDS IN THE PACIFIC NORTHWEST SCE and PG&E have publicly disclosed that their liquidity has been materially and adversely affected because of, among other things, their inability to pass on to ratepayers the prices each has paid for energy and ancillary services procured through the PX and the ISO. We are closely monitoring developments in the California energy market and the potential impact of these 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 marketing and trading exposures. Based on our 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, the 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 the FERC after the California ISO and PX provide necessary historical data. The FERC also ordered an evidentiary proceeding to discuss and evaluate possible refunds for the Pacific Northwest. The ALJ at the 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 the FERC Commissioners. Although the FERC has 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, as to amounts alleged in the proceedings, will have a material adverse impact on our financial position, results of operations or liquidity. On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including Pinnacle West, failed to properly file rate information at the FERC in connection with sales to California from 2000 to present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET AL., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are "found to exceed just and reasonable levels." The complaint indicates that Pinnacle West sold approximately $106 million of power to the California Department of Water Resources from January 17, 2001 to October 31, 2001 and does not allege any 66 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS amount above "just and reasonable levels." Pinnacle West believes that the claims as they relate to Pinnacle West are without merit. CONSTRUCTION PROGRAM Total capital expenditures in 2002 are estimated at $498 million. LITIGATION We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In our opinion, the ultimate resolution of these matters will not have a material adverse effect on our financial statements or liquidity. 11. NUCLEAR DECOMMISSIONING COSTS We recorded $11 million for nuclear decommissioning expense in each of the years 2001, 2000, and 1999. We estimate it will cost about $1.8 billion ($506 million in 2001 dollars) to decommission our share of the three Palo Verde units. The majority of decommissioning costs are expected to be incurred over a 14-year period beginning in 2024. We charge decommissioning costs to expense over each unit's operating license term and include them in the accumulated depreciation balance until each unit is retired. Nuclear decommissioning costs are recovered in rates. Our current estimates are based on a 2001 site-specific study for Palo Verde that assumes the prompt removal/dismantlement method of decommissioning. An independent consultant prepared this study. We are required to update the study every three years. To fund the costs we expect to incur to decommission the plant, we established external decommissioning trusts in accordance with NRC regulations. We invest the trust funds primarily in fixed income securities and domestic stock and classify them as available for sale. Realized and unrealized gains and losses are reflected in accumulated depreciation in accordance with industry practice. The following table shows the cost and fair value of our nuclear decommissioning trust fund assets which are reported in investments and other assets on the balance sheets at December 31, 2001 and 2000 (dollars in millions): 67 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 2001 2000 -------- -------- Trust fund assets - at cost Fixed income securities $ 103 $ 94 Domestic stock 61 52 -------- -------- Total $ 164 $ 146 ======== ======== Trust fund assets - fair value Fixed income securities $ 106 $ 97 Domestic stock 96 100 -------- -------- Total $ 202 $ 197 ======== ======== See Note 2 for information on a new accounting standard on accounting for certain liabilities related to closure or removal of long-lived assets. 12. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) Quarterly financial information for 2001 and 2000 is as follows:
(dollars in thousands) 2001 -------------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 ---------- ---------- ------------ ----------- Electric operating revenues (a) Electric retail segment $ 412,807 $ 739,317 $ 973,398 $ 436,566 Marketing and trading segment (b) 247,022 230,894 65,129 6,195 Operating income (a) $ 97,034 $ 95,238 $ 135,139 $ 71,567 Income before accounting change $ 64,606 $ 69,639 $ 107,556 $ 38,887 Cumulative effect of change in accounting - net of income tax (2,755) -- (12,446) -- ---------- ---------- ---------- ---------- Net income $ 61,851 $ 69,639 $ 95,110 $ 38,887 ========== ========== ========== ==========
68 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS (dollars in thousands)
2000 -------------------------------------------------------- QUARTER ENDED March 31 June 30 September 30 December 31 ---------- ---------- ------------ ----------- Electric operating revenues (a) Electric retail segment $ 379,428 $ 547,091 $1,156,659 $ 455,572 Marketing and trading segment (b) 35,040 104,386 93,141 162,825 Operating income (a) $ 64,849 $ 131,034 $ 159,589 $ 90,764 ---------- ---------- ---------- ---------- Net income $ 32,775 $ 95,851 $ 124,231 $ 53,737 ========== ========== ========== ==========
(a) Electric revenues are seasonal in nature, with the peak sales periods generally occurring during the summer months. Comparisons among quarters of a year may not represent overall trends and changes in operations. (b) See Note 18 for information related to a change in presentation of certain marketing and trading revenues to a net basis. 13. FAIR VALUE OF FINANCIAL INSTRUMENTS We believe that the carrying amounts of our cash equivalents and commercial paper are reasonable estimates of their fair values at December 31, 2001 and 2000 due to their short maturities. We hold investments in debt and equity securities for purposes other than trading. The December 31, 2001 and 2000 fair values of such investments, which we determine by using quoted market values, approximate their carrying amount. On December 31, 2001, the carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.08 billion, with an estimated fair value of $2.10 billion. The carrying value of our long-term debt (excluding a capitalized lease obligation) was $2.06 billion on December 31, 2000, with an estimated fair value of $2.11 billion. The fair value estimates are based on quoted market prices of the same or similar issues. 14. STOCK-BASED COMPENSATION Pinnacle West offers two stock incentive plans for officers and key employees of our company. One of the plans (1994 plan) provides for the granting of new options (which may be non-qualified stock options or incentive stock options) of up to 3.5 million shares at a price per option not less than the fair market value on the date the option is granted. The other plan (1985 plan) includes outstanding options but no new options will be granted from the plan. Options vest one-third 69 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS of the grant per year beginning one year after the date the option is granted and expire ten years from the date of the grant. The plan also provides for the granting of any combination of shares of restricted stock, stock appreciation rights or dividend equivalents. The awards outstanding under the incentive plans at December 31, 2001 are 1,832,725 non-qualified stock options, 237,833 shares of restricted stock, and no incentive stock options, stock appreciation rights or dividend equivalents. SFAS No. 123, "Accounting for Stock-Based Compensation" encourages, but does not require, that a company record compensation expense based on the fair value of options granted (the fair value method). We continue to recognize expense based on Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." If we had recorded compensation expense based on the fair value method, our net income would have been reduced to the following pro forma amounts (dollars in thousands): 2001 2000 1999 ---------- ---------- ---------- Net income As reported $ 265,487 $ 306,594 $ 128,437 Pro forma (fair value method) $ 263,594 $ 305,610 $ 127,658 In order to present the pro forma information above, we calculated the fair value of each fixed stock option in the incentive plans using the Black-Scholes option-pricing model. The fair value was calculated based on the date the option was granted. The following weighted-average assumptions were also used in order to calculate the fair value of the stock options: 2001 2000 1999 ---------- ---------- ---------- Risk-free interest rate 4.08% 5.81% 5.68% Dividend yield 3.70% 3.48% 3.33% Volatility 27.66% 32.00% 20.50% Expected life (months) 60 60 60 70 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 15. BUSINESS SEGMENTS We have two principal business segments (determined by products, services and regulatory environment) which consist of regulated retail electricity business and related activities (electric retail business segment) and competitive business activities (marketing and trading segment). Our electric retail business segment currently includes activities related to electricity transmission and distribution, as well as electricity generation. Our marketing and trading business segment currently includes activities related to wholesale marketing and trading. These reportable segments reflect a change in the reporting of our segment information. Before the fourth quarter of 2001, we had two segments (generation and delivery). The "generation segment" information combined our marketing and trading activities with our generation of electricity activities. The "delivery segment" included transmission and distribution activities. In the fourth quarter of 2001, we filed with the ACC a proposed rule variance and purchase power agreement with the ACC (see Note 3) that inherently views our business in the new reportable segments described herein. Internal management reporting has been changed to reflect this alignment. The corresponding information for earlier periods has been restated. Financial data for the business segments is provided as follows (dollars in millions): Business Segments for Year Ended December 31, 2001 Electric Marketing and Retail Trading (a) Total -------- ----------- -------- Operating revenues $ 2,562 $ 549 $ 3,111 Purchased power and fuel costs 1,227 314 1,541 Other operating expenses 568 -- 568 -------- -------- -------- Operating margin 767 235 1,002 Depreciation and amortization 421 -- 421 Interest and other expenses 118 -- 118 -------- -------- -------- Pretax margin 228 235 463 Income taxes 90 93 183 -------- -------- -------- Income before accounting change 138 142 280 Cumulative effect of change in accounting for derivatives - net of income taxes of $10 (15) -- (15) -------- -------- -------- Net income $ 123 $ 142 $ 265 ======== ======== ======== Total assets $ 6,228 $ 139 $ 6,367 ======== ======== ======== Capital expenditures $ 471 $ -- $ 471 ======== ======== ======== 71 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS Business Segments for Year Ended December 31, 2000 Electric Marketing and Retail Trading (a) Total -------- ----------- -------- Operating revenues $ 2,539 $ 395 $ 2,934 Purchased power and fuel costs 1,065 267 1,332 Other operating expenses 541 -- 541 -------- -------- -------- Operating margin 933 128 1,061 Depreciation and amortization 425 -- 425 Interest and other expenses 133 -- 133 -------- -------- -------- Pretax margin 375 128 503 Income taxes 145 51 196 -------- -------- -------- Net income $ 230 $ 77 $ 307 ======== ======== ======== Total assets $ 6,096 $ 318 $ 6,414 ======== ======== ======== Capital expenditures $ 472 $ -- $ 472 ======== ======== ======== Business Segments for Year Ended December 31, 1999 Electric Marketing and Retail Trading (a) Total -------- ----------- -------- Operating revenues $ 1,915 $ 154 $ 2,069 Purchased power and fuel costs 432 137 569 Operating expenses 547 -- 547 -------- -------- -------- Operating margin 936 17 953 Depreciation and amortization 416 -- 416 Interest and preferred stock dividend requirements 137 -- 137 -------- -------- -------- Pretax margin 383 17 400 Income taxes 126 7 133 Extraordinary charge - net of income taxes of $94 (140) -- (140) -------- -------- -------- Earnings for common stock $ 117 $ 10 $ 127 ======== ======== ======== Total assets $ 6,056 $ 62 $ 6,118 ======== ======== ======== Capital expenditures $ 332 $ -- $ 332 ======== ======== ======== (a) See Note 18 for information related to a change in presentation of certain marketing and trading revenues and purchased power and fuel costs to a net basis. 72 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 16. 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 allowance and credits. The changes in market value of such contracts have a high correlation to price changes in the hedged commodity. In addition, subject to specified risk parameters established by the Pinnacle West Board of Directors and monitored by Pinnacle West's ERMC, we engage in trading activities intended to profit from market price movements. We are exposed to losses in the event of nonperformance or nonpayment by counterparties. We use a risk management process to assess and monitor the financial exposure of this and all other counterparties. Despite the fact that the great majority of our 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. Counterparties in the portfolio consist principally of major energy companies, municipalities, and local distribution companies. We maintain credit policies that we believe minimize overall credit risk to within acceptable limits. Determination of the credit quality of our counterparties is based upon a number of factors, including credit ratings and our evaluation of their financial condition. In many contracts, we employ collateral requirements and standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. Credit reserves are established representing our estimated credit losses on our overall exposure to counterparties. See Note 1 for a discussion of our credit reserve policy. 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 sheets and measure those instruments at fair value. Changes in the fair value of derivative financial instruments are either recognized periodically in income or shareholders' equity (as a component of other comprehensive income), depending on whether or not the derivative meets specific hedge accounting criteria. Hedge effectiveness is measured based on the relative changes in fair value between the derivative contract and the hedged item over time. Any change in the fair value resulting from ineffectiveness is recognized immediately in net income. This new standard may result in additional volatility in our net income and comprehensive income. As a result of adopting SFAS No. 133, we recognized $118 million of derivative assets and $16 million of derivative liabilities in our balance sheets as of January 1, 2001. Also as of January 1, 2001, we recorded a $3 million after-tax loss in net income and a $64 million after-tax gain in equity (as a component of other comprehensive income) both as a cumulative effect of a change in accounting principle. The gain resulted from unrealized gains on cash flow hedges. 73 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS In June 2001, the FASB issued new guidance related to electricity contracts. The effective date of this new guidance was July 1, 2001. 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. The loss resulted primarily from electricity options contracts. The gain resulted from unrealized gains on cash flow hedges. The impact of the new guidance is reflected in net income and other comprehensive income as a cumulative effect of change in accounting principle. In December 2001, the FASB issued revised guidance on the accounting for electricity contracts with option characteristics and the accounting for contracts that combine a forward contract and a purchased option contract. The effective date for the revised guidance is April 1, 2002. We are currently evaluating the new guidance to determine what impact, if any, it will have on our financial statements. The change in derivative fair value included in the statements of income for the year ending December 31, 2001 is comprised of the following (dollars in thousands): December 31, 2001 ---------- Ineffective portion of derivatives qualifying for hedge accounting (a) $ (8,371) Discontinuance of cash flow hedges for forecasted transactions that will not occur (9,525) Reclassification of mark-to-market losses to realized 25,948 ---------- Total $ 8,052 ========== (a) Time value component of options excluded from assessment of hedge effectiveness. As of December 31, 2001, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted transactions is thirty-six months. During the twelve months ended December 31, 2002, we estimate that a net loss of $23 million before income taxes will be reclassified from accumulated other comprehensive loss as an offset to the effect on earnings of market price changes for the related hedged transaction. Net gains and losses on instruments utilized for trading activities are recognized in marketing and trading revenues on a current basis (the mark-to-market method). Trading positions are measured at fair value as of the balance sheet date. The unrealized trading gains recognized in marketing and trading revenues were $85 million for the year ended December 31, 2001 and $14 million for the year ended December 31, 2000. 74 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS 17. SUBSEQUENT EVENTS On March 1, 2002, we issued $375 million of 6.50% Notes due 2012. On March 15, 2002, we announced the redemption on April 15, 2002 of approximately $125 million of our First Mortgage Bonds, 8.75% Series due 2024. On March 19, 2002, the State of California filed a complaint with the FERC alleging that wholesale sellers of power and energy, including Pinnacle West, failed to properly file rate information at the FERC in connection with sales to California from 2000 to the present. STATE OF CALIFORNIA V. BRITISH COLUMBIA POWER EXCHANGE ET. AL., Docket No. EL02-71-000. The complaint requests the FERC to require the wholesale sellers to refund any rates that are "found to exceed just and reasonable levels." The complaint indicates that Pinnacle West sold approximately $106 million of power to California Department of Water Resources from January 17, 2001 to October 31, 2001 and does not allege any amount above "just and reasonable levels." Pinnacle West believes that the claims as they relate to Pinnacle West are without merit. See Note 3 for information relating to the March 22, 2002 ACC Staff report addressing issues in the generic docket. 18. SUBSEQUENT EVENT - NET REVENUE PRESENTATION CHANGE In June 2002, the FASB's EITF issued certain guidance related to energy trading activities in EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities." The new guidance, which was effective July 1, 2002, required that all energy trading activities within the scope of EITF 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," be presented on a net basis in revenues and that prior period amounts be restated. In October 2002, the EITF reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" should be shown net in the income statement if the derivative is held for trading purposes. This decision effectively supersedes the guidance provided at the June meeting. Historically, we have reported our electric revenues and purchased power and fuel costs on a gross basis in our statements of income, with the exception of unrealized gains and losses recorded under the mark-to-market method. When the gain or loss was realized, the gross amount was recorded as revenue and purchased power and fuel costs in the statements of income. Throughout this document, we have made the reclassification change to net revenues and purchased power and fuel costs related to our energy trading activities. This change has no impact on our gross margin, net income or cash provided by operating activities. The following table shows the impact of the change on our Marketing and Trading segment revenues and purchased power and fuel costs: 75 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS
Year ended December 31, (dollars in thousands) ---------------------------------- 2001 2000 1999 -------- -------- -------- Marketing and trading revenues before reclassification $748,704 $941,502 $378,076 Less: Purchased power and fuel costs netted with revenues 199,464 546,110 223,950 -------- -------- -------- Marketing and trading revenues after reclassification $549,240 $395,392 $154,126 ======== ======== ======== Marketing and trading purchased power and fuel before reclassification $513,455 $813,142 $360,472 Less: Purchased power and fuel costs netted with revenues 199,464 546,110 223,950 -------- -------- -------- Marketing and trading purchased power and fuel after reclassification $313,991 $267,032 $136,522 ======== ======== ========
In the October 2002 meeting, the EITF also rescinded EITF 98-10. This guidance is effective immediately for all new contracts and on January 1, 2003 for existing contracts. As such, energy trading contracts will be accounted for on an accrual basis with the associated revenues and costs recorded at the time the contracted commodities are delivered or received, unless the contracts are required to be marked to market as derivatives under SFAS No. 133 or if allowed by other guidance. We adopted the guidance for all contracts in the fourth quarter of 2002. The impact of this guidance was immaterial to our financial statements. In addition, we have presented in our income statements our operating revenues and purchased power and fuel separately for our electric retail and marketing and trading segments. We also have presented our other income and expense items on a gross basis in our income statements. 76 ARIZONA PUBLIC SERVICE COMPANY NOTES TO FINANCIAL STATEMENTS ARIZONA PUBLIC SERVICE COMPANY SCHEDULE II - RESERVE FOR UNCOLLECTIBLES (DOLLARS IN THOUSANDS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E ADDITIONS --------------------- CHARGED BALANCE AT TO COST CHARGED TO BALANCE AT BEGINNING AND OTHER END OF DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD ----------- --------- -------- -------- ---------- ------- RESERVE FOR UNCOLLECTIBLES Year ended December 31, 2001 $ 2,380 $ 7,609 $ -- $ 6,640 $ 3,349 Year ended December 31, 2000 $ 1,538 $ 5,438 $ -- $ 4,596 $ 2,380 Year ended December 31, 1999 $ 1,725 $ 4,778 $ -- $ 4,965 $ 1,538
77 ITEM 7. FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION AND EXHIBITS. (c) Exhibits. Exhibit No. Description ----------- ----------- 23.1 Consent of Deloitte & Touche LLP 78 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 hereunto duly authorized. ARIZONA PUBLIC SERVICE COMPANY (Registrant) Dated: February 26, 2003 By: Barbara M. Gomez ------------------------------------ Barbara M. Gomez Treasurer 79 EX-23.1 3 ex23-1.txt CONSENT OF DELOITTE & TOUCHE LLP EXHIBIT 23.1 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 33-51085 and Registration Statement No. 333-90824 of Arizona Public Service Company on Form S-3 and in Registration Statement No. 333-46161 of Arizona Public Service Company on Form S-8 of our report dated February 8, 2002 (March 22, 2002, as to Note 17 and February 24, 2003 as to Note 18) (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the change in 2001 in the method of accounting for derivatives and hedging activities in order to comply with the provisions of Statement of Financial Accounting Standards No. 133) appearing in this Current Report on Form 8-K of Arizona Public Service Company. DELOITTE & TOUCHE LLP DELOITTE & TOUCHE LLP Phoenix, Arizona February 24, 2003 -----END PRIVACY-ENHANCED MESSAGE-----