10-Q 1 f10q_0331.txt TEXT OF 3-31-01 FORM 10-Q UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITES EXCHANGE ACT OF 1934 For the period ended March 31, 2001 -------------- - OR - [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _________________ Commission file number 1-6986 ------ PUBLIC SERVICE COMPANY OF NEW MEXICO ------------------------------------ (Exact name of registrant as specified in its charter) New Mexico 85-0019030 ---------- ---------- (State or other jurisdiction of (I.R.S. Employer Incorporation of organization) Identification No.) Alvarado Square, Albuquerque, New Mexico 87158 ---------------------------------------------- (Address of principal executive offices) (Zip Code) (505) 241-2700 -------------- (Registrant's telephone number, including area code) ------------------------------ (Former name, former address and former fiscal year, if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock-$5.00 par value 39,117,799 shares ---------------------------- ----------------- Class Outstanding at May 1, 2001 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES INDEX Page No. PART I. FINANCIAL INFORMATION: Report of Independent Public Accountants........................ 3 ITEM 1. FINANCIAL STATEMENTS Consolidated Statements of Earnings - Three Months Ended March 31, 2001 and 2000...................... 4 Consolidated Balance Sheets - March 31, 2001 and December 31, 2000............................ 5 Consolidated Statements of Cash Flows - Three Months Ended March 31, 2001 and 2000...................... 7 Notes to Consolidated Financial Statements...................... 8 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.......... 23 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK............................................ 51 PART II. OTHER INFORMATION: ITEM 1. LEGAL PROCEEDINGS......................................... 52 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.......................... 54 Signature ....................................................... 56 2 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Public Service Company of New Mexico: We have reviewed the accompanying condensed consolidated balance sheet of PUBLIC SERVICE COMPANY OF NEW MEXICO (a New Mexico corporation) and subsidiaries as of March 31, 2001, and the related condensed consolidated statements of earnings for the three-month periods ended March 31, 2001 and 2000, and the condensed consolidated statements of cash flows for the three-month periods ended March 31, 2001 and 2000. These financial statements are the responsibility of the company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States. We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet as of December 31, 2000, and the related consolidated statements of earnings, capitalization and cash flows for the year then ended (not presented separately herein), and in our report dated January 26, 2001, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2000 is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. ARTHUR ANDERSEN LLP Albuquerque, New Mexico May 9, 2001 3 ITEM 1. FINANCIAL STATEMENTS PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited) Three Months Ended March 31 --------------------------------- 2001 2000 --------------- ------------- (In thousands, except per share amounts) Operating Revenues: Utility................................... $326,459 $220,643 Generation and Trading.................... 491,165 176,298 Unregulated businesses.................... - 349 Intersegment elimination.................. (81,094) (75,999) --------------- ------------- Total operating revenues................ 736,530 321,291 --------------- ------------- Operating Expenses: Cost of energy sold....................... 497,098 167,723 Administrative and general................ 39,488 32,196 Energy production costs................... 35,025 35,642 Depreciation and amortization............. 24,219 24,010 Transmission and distribution costs....... 15,277 15,280 Taxes, other than income taxes............ 7,217 7,666 Income taxes.............................. 40,906 7,827 --------------- ------------- Total operating expenses................ 659,230 290,344 --------------- ------------- Operating income........................ 77,300 30,947 --------------- ------------- Other Income and Deductions, Net of Tax 2,634 7,505 --------------- ------------- Income before interest charges.......... 79,934 38,452 --------------- ------------- Interest Charges: Interest on long-term debt................ 15,643 15,781 Other interest charges.................... 739 719 --------------- ------------- Net interest charges........................ 16,382 16,500 --------------- ------------- Net Earnings................................ 63,552 21,952 Preferred Stock Dividend Requirements....... 146 146 --------------- ------------- Net Earnings Applicable to Common Stock..... $ 63,406 $ 21,806 =============== ============= Net Earnings per Common Share: Basic..................................... $ 1.62 $ 0.55 =============== ============= Diluted................................... $ 1.60 $ 0.55 =============== ============= Dividends Paid per Common Share............. $ 0.20 $ 0.20 =============== ============= The accompanying notes are an integral part of these financial statements. 4
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS March 31, December 31, 2001 2000 -------------- -------------- (Unaudited) (In thousands) ASSETS Utility Plant: Electric plant in service.................................... $2,012,912 $2,030,813 Gas plant in service......................................... 550,744 553,755 Common plant in service and plant held for future use........ 37,002 36,678 -------------- -------------- 2,600,658 2,621,246 Less accumulated depreciation and amortization............... 1,175,053 1,153,377 -------------- -------------- 1,425,605 1,467,869 Construction work in progress................................ 197,585 123,653 Nuclear fuel, net of accumulated amortization of $21,734 and $19,081...................................... 24,287 25,784 -------------- -------------- Net utility plant.......................................... 1,647,477 1,617,306 -------------- -------------- Other Property and Investments: Other investments............................................ 455,208 479,821 Non-utility property, net of accumulated depreciation of $1,730 and $1,644........................................ 3,601 3,666 -------------- -------------- Total other property and investments....................... 458,809 483,487 -------------- -------------- Current Assets: Cash and cash equivalents.................................... 161,301 107,691 Accounts receivables, net of allowance for uncollectible accounts of $10,998 and $8,963........................... 276,129 242,742 Other receivables............................................ 45,759 64,857 Inventories.................................................. 35,985 36,091 Regulatory assets............................................ 31,463 47,604 Other current assets......................................... 52,634 11,417 -------------- -------------- Total current assets....................................... 603,271 510,402 -------------- -------------- Deferred Charges: Regulatory assets............................................ 227,054 226,849 Prepaid benefit costs........................................ 19,727 18,116 Other deferred charges....................................... 40,716 38,073 -------------- -------------- Total current assets....................................... 287,497 283,038 -------------- -------------- $ 2,997,054 $ 2,894,233 ============== ==============
The accompanying notes are an integral part of these financial statements. 5
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS March 31, December 31, 2001 2000 --------------- --------------- (Unaudited) CAPITALIZATION AND LIABILITIES (In thousands) Capitalization: Common stockholders' equity: Common stock................................................... $ 195,589 $ 195,589 Additional paid-in capital..................................... 431,737 432,222 Accumulated other comprehensive income, net of tax............. 15,372 (27) Retained earnings.............................................. 360,241 296,843 --------------- --------------- Total common stockholders' equity........................... 1,002,939 924,627 Minority interest................................................. 11,926 12,211 Cumulative preferred stock without mandatory redemption requirements...................................... 12,800 12,800 Long-term debt, less current maturities........................... 953,839 953,823 --------------- --------------- Total capitalization........................................ 1,981,504 1,903,461 --------------- --------------- Current Liabilities: Accounts payable.................................................. 217,915 257,991 Accrued interest and taxes........................................ 84,460 36,889 Other current liabilities......................................... 69,036 67,758 --------------- --------------- Total current liabilities................................... 371,411 362,638 --------------- --------------- Deferred Credits: Accumulated deferred income taxes................................... 157,002 166,249 Accumulated deferred investment tax credits......................... 43,834 47,853 Regulatory liabilities.............................................. 64,918 65,552 Regulatory liabilities related to accumulated deferred income tax... 20,696 20,696 Accrued postretirement benefit costs................................ 18,448 11,899 Other deferred credits.............................................. 339,241 315,885 --------------- --------------- Total deferred credits........................................... 644,139 628,134 --------------- --------------- $2,997,054 $2,894,233 =============== ===============
The accompanying notes are an integral part of these financial statements. 6
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Three Months Ended March 31, ------------------------------ 2001 2000 -------------- -------------- (In thousands) Cash Flows From Operating Activities: Net earnings.......................................................... $ 63,552 $ 21,952 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization..................................... 25,080 26,805 Other, net........................................................ 6,462 (3,406) Changes in certain assets and liabilities: Accounts receivables............................................ (33,388) 15,022 Other assets.................................................... 23,630 27,342 Accounts payable................................................ (40,075) (61,711) Accrued taxes................................................... 49,621 4,376 Other liabilities............................................... 14,630 5,198 -------------- -------------- Net cash flows provided from operating activities............... 109,512 35,578 -------------- -------------- Cash Flows Used for Investing Activities: Utility plant additions............................................... (55,820) (22,361) Return on PVNGS lease obligation bonds................................ 8,535 8,636 Other investing....................................................... 109 (3,155) -------------- -------------- Net cash flows used for investing activities.................... (47,176) (16,880) -------------- -------------- Cash Flows Used for Financing Activities: Repayments............................................................ - (32,800) Common stock repurchase............................................... - (18,854) Exercise of employee stock options.................................... (476) - Dividends paid........................................................ (7,965) (8,182) Other financing....................................................... (285) (288) -------------- -------------- Net cash flows used for financing activities.................... (8,726) (60,124) -------------- -------------- Increase (Decrease) in Cash and Cash Equivalents........................ 53,610 (41,426) Beginning of Period..................................................... 107,691 120,399 -------------- -------------- End of Period........................................................... $161,301 $ 78,973 ============== ============== Supplemental Cash Flow Disclosures: Interest paid......................................................... $ 17,748 $ 20,318 ============== ============== Income taxes paid, net ............................................... $ 3,400 $ 23 ============== ==============
The accompanying notes are an integral part of these financial statements. 7 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Accounting Policies and Responsibilities for Financial Statements In the opinion of management of Public Service Company of New Mexico (the "Company"), the accompanying interim consolidated financial statements present fairly the Company's financial position at March 31, 2001 and December 31, 2000, the consolidated results of its operations for the three months ended March 31, 2001 and 2000 and the consolidated statements of cash flows for the three months ended March 31, 2001 and 2000. These statements are presented in accordance with the rules and regulations of the United States Securities and Exchange Commission ("SEC"). Accordingly, they are unaudited, and certain information and footnote disclosures normally included in the Company's annual consolidated financial statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these statements should refer to the Company's audited consolidated financial statements and notes thereto for the year ended December 31, 2000, which are included on the Company's Annual Report on Form 10-K for the year ended December 31, 2000. The results of operations presented in the accompanying financial statements are not necessarily representative of operations for an entire year. Certain amounts in the 2000 consolidated financial statements and notes have been reclassified to conform to the 2001 financial statement presentation. (2) Nature of Business and Segment Information The Company is an investor-owned integrated utility engaged in the generation, transmission, distribution and sale and trading of electricity, and the transportation, distribution and sale of natural gas. In addition, the Company provides energy and utility related services under its wholly-owned subsidiary, Avistar, Inc. ("Avistar"). The Company's principal business segments are Utility Operations, which include the Electric Product Offering ("Electric") and the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations ("Generation"). The Electric Product Offering consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment due to its immateriality and is combined with the distribution business line for disclosure purposes. Electric procures all of its electric power needs from the Company's Generation and Trading Operations. These intersegment sales are priced using internally developed transfer pricing, and are not based on market rates. Customer electric rates are regulated by the New Mexico Public Regulation Commission ("PRC") and determined on a basis that includes the recovery of the cost of power production by the Company's Generation and Trading Operations and a return on the related assets, among other things. 8 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (2) Nature of Business and Segment Information (Continued) UTILITY OPERATIONS Electric The Company provides jurisdictional retail electric service to a large area of north central New Mexico, including the cities of Albuquerque and Santa Fe, and certain other areas of New Mexico. The Company owns or leases 2,781 circuit miles of transmission lines, interconnected with other utilities east into Texas, west into Arizona, and north into Colorado and Utah. Gas The Company's gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe. The Company's customer base includes both sales-service customers and transportation-service customers. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. GENERATION AND TRADING OPERATIONS The Company's generation and trading operations serve four principal markets. These include sales to the Company's Utility Operations to cover jurisdictional electric demand, sales to firm-requirements wholesale customers, other contracted sales to third parties for a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time and energy sales made on an hourly basis at fluctuating, spot-market rates. These latter two markets constitute the Company's power trading operations. As of March 31, 2001 the total net generation capacity of facilities owned or leased by the Company was 1,653 MW, including a 132 MW power purchase contract accounted for as an operating lease. In addition to generation capacity the Company purchases power in open market. UNREGULATED The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a New Mexico corporation and is currently engaged in certain unregulated, non-utility businesses, including energy and utility-related services previously operated by the Company. Unregulated also includes certain corporate activities, which are not material. REGULATION AND RESTRUCTURING In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delays the original implementation dates by approximately five years, including the requirement for corporate separation of certain deregulated activities from activities 9 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (2) Nature of Business and Segment Information (Continued) regulated by the PRC. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The amendments require that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of the regulated and deregulated activities, by July 1, 2001. In April 2001, the Company filed its application for the creation of a holding company. Hearings on the matter began May 10, 2001. The Company is unable to predict what terms and conditions may be imposed as part of the approval process. Previously, in June 2000, shareholders approved the mandatory share exchange necessary to implement a holding company structure. In April 2001, the Company's Board of Directors amended the articles of incorporation of the proposed holding company to rename the holding company "PNM Resources, Inc." (PNM Resources). The holding company was originally approved by shareholders last year as Manzano Corporation. The Company is unable to predict the outcome of its application and whether or not the holding company proposal will be approved by the PRC with acceptable conditions. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented. The Company believes that its ability to form a new holding company and expand generation assets in an unregulated environment will give it the flexibility it needs to pursue its strategic plan despite the delay in customer choice and corporate separation. The Company is unable to predict the form its restructuring will take under the delayed implementation of customer choice. The formulation of a restructuring plan will be dependent on future business conditions at the expected time customer choice is implemented (See "Other Issues Facing The Company - Recovery of Certain Costs Under The Restructuring Act" below). RISKS AND UNCERTAINTIES The Company's future results may be affected by changes in regional economic conditions; fluctuations in fuel, purchased power and gas prices; the actions of utility regulatory commissions; changes in law; environmental regulations and external factors such as the weather. As a result of State and Federal regulatory reforms, the public utility industry is undergoing a fundamental change. As this occurs, the electric generation business is transforming into a competitive marketplace. In turn, these reforms are being revisited as a result of the energy crisis in California, escalating prices for power elsewhere in the Western United States, and concerns over inadequate capacity, among other conditions. The Company's future results will be impacted by its ability to recover its stranded costs, the market price of electricity and natural gas costs incurred previously in providing power generation to electric service customers, the costs of transition to an unregulated status, future regulatory actions, and the price of power in the wholesale markets. In addition, as a result of deregulation, the Company may face competition from companies with greater financial and other resources. 10 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (2) Nature of Business and Segment Information (Continued) Summarized financial information by business segment for the three months ended March 31, 2001 and 2000 is as follows:
Utility ------------------------------------ Generation Electric Gas Total and Trading Unregulated Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 2001: Operating revenues: External customers............ $134,346 $191,936 $326,282 $410,248 $ - $736,530 Intersegment revenues......... 177 - 177 80,917 - 81,094 Depreciation and amortization.... 8,025 5,290 13,315 10,895 9 24,219 Interest income.................. 457 286 743 12,625 1,831 15,199 Net interest charges............. 4,273 2,986 7,259 9,095 28 16,382 Income tax expense (benefit) From continuing operations..... 7,699 5,682 13,381 35,772 (6,521) 42,632 Operating income (loss).......... 15,793 11,387 27,180 59,027 (8,907) 77,300 Segment net income (loss)........ 11,749 8,671 20,420 54,587 (11,455) 63,552 Total assets..................... 724,513 517,412 1,241,925 1,538,209 216,920 2,997,054 Gross property additions......... 11,440 6,574 18,014 36,342 1,464 55,820 2000: Operating revenues: External customers............ $125,922 $ 94,545 $220,467 $100,475 $ 349 $321,291 Intersegment revenues......... 177 - 177 75,822 - 75,999 Depreciation and amortization.... 8,326 5,366 13,692 10,312 6 24,010 Interest income.................. 46 136 182 9,779 1,304 11,265 Net interest charges............. 4,471 2,854 7,325 9,016 159 16,500 Income tax expense (benefit) from continuing operations..... 5,996 3,726 9,722 5,720 (2,741) 12,701 Operating income (loss).......... 13,892 8,118 22,010 13,836 (4,899) 30,947 Segment net income (loss)........ 9,266 5,500 14,766 11,370 (4,184) 21,952 Total assets..................... 774,300 454,224 1,228,524 1,374,329 23,444 2,626,297 Gross property additions......... 9,846 4,737 14,583 7,778 - 22,361
11 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (3) Comprehensive Income Changes in comprehensive income are as follows:
Three Months Ended March 31 ------------------------- 2001 2000 ----------- ------------ (In thousands) Net Earnings.................................................................... $63,552 $21,952 ----------- ------------ Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities: Unrealized holding gains (losses) arising during the period............... (948) 1,475 Less: reclassification adjustment for gains included in net income........................................................... (296) (1,499) Minimum pension liability adjustment......................................... 780 - Mark-to-market adjustment for certain derivative transactions (see Footnote 4): Initial implementation of SFAS 133 designated cash flow hedges............................................................... 6,148 - Change in fair market value of designated cash flow hedges..................................................... 9,715 - ----------- ------------ Total Other Comprehensive Income (Loss)...................................... 15,399 (24) ----------- ------------ Total Comprehensive Income...................................................... $78,951 $21,928 =========== ============
The Company's investments held in grantor trusts for nuclear decommissioning and certain retirement benefits are classified as available-for-sale, and accordingly unrealized holding gains and losses are recognized as a component of comprehensive income. Realized gains and losses are included in earnings. Net losses to the Company's pension plans not yet recognized as net periodic pension costs (or additional minimum liability) are reported as a component of comprehensive income. Changes in the liability are adjusted as necessary. All components of comprehensive income are recorded, net of any tax benefit or expense. A deferred asset or liability is established for the resulting temporary difference. (4) Financial Instruments The Company implemented Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"), as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at their fair value. SFAS 133, as amended, also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness 12 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (4) Financial Instruments (Continued) of transactions that receive hedge accounting. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices and adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. The Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to assess and monitor the financial conditions of counterparties. The Company's credit risk with its largest counterparty as of March 31, 2001 was $20.2 million. Natural Gas Contracts Utility Operations Pursuant to a 1997 order issued by the New Mexico Public Utility Commission ("NMPUC"), predecessor to the PRC, the Company's utility operations have previously and continue to enter into swaps to hedge certain portions of natural gas supply contracts in order to protect the Company's natural gas customers from the risk of adverse price fluctuations in the natural gas market. The financial impacts of all hedge gains and losses from swaps are recoverable through the Company's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by the gains or losses generated by these instruments. The Company contracted for gas price caps, a type of hedge, to protect its natural gas customers from price risk during the 2000-2001 heating season through the use of financial hedging tools. The Company expended $5 million to purchase physical options that limit the maximum amount the Company would pay for gas during the winter heating season. The Company recovered the $5 million in hedging costs during the months of October and November 2000 in equal $2.5 million allotments as a component of the PGAC. Results of the winter 2000-2001 hedging activities were an estimated $27 million benefit to system gas supply customers in the form of lower gas costs net of the cost of the price caps. As of March 31, 2001, all gas option contracts were closed. Generation and Trading Operations The Company's Generation and Trading Operations conduct a hedging program to reduce its exposure to fluctuations in prices for natural gas used as a fuel source for some of its generation. In the first quarter of 2001, the Generation Operations purchased futures contracts 13 (4) Financial Instruments (Continued) for a portion of its anticipated natural gas needs in the second, third and fourth quarters. The futures contracts lock-in the Company's natural gas purchase prices at $5.37 to $6.40 per MMBTU and have a notional principal of $20.9 million. Simultaneously, a delivery location basis swap was purchased for quantities corresponding to the futures quantities to protect against price differential changes at the specific delivery points. The Company is accounting for these transactions as cash flow hedges; accordingly, gains and losses related to these transactions are deferred and recorded as a component of Other Comprehensive Income. These gains and losses are reclassified and recognized in earnings as an adjustment to the Company's cost of fuel when the hedged forecasted transaction effects earnings. The assessment of hedge effectiveness is based on the changes in the futures contract price as adjusted for the delivery point basis swap. There was no hedge ineffectiveness recognized in the three months ended March 31, 2001. Electricity Contracts To take advantage of market opportunities associated with the purchase and sale of electricity, the Company's wholesale power operation periodically enters into derivative financial instrument contracts. The Company generally accounts for these financial instruments as trading activities under the accounting guidelines set forth under The Emerging Issues Task Force ("EITF") Issue No. 98-10. As a result, these contracts are marked to market at the end of each period. The related gains and losses for these derivative instruments are recorded as adjustments to operating revenues. Through March 31, 2001, the Company's wholesale electric trading operations settled trading contracts for the sale of electricity that generated $11.8 million of electric revenues by delivering 122 million KWh. The Company purchased $10.9 million or 102 million KWh of electricity to support these contractual sales and other open market sales opportunities. As of March 31, 2001, the Company had open trading contract positions to buy $77.2 million and to sell $35.7 million of electricity. At March 31, 2001, the Company had a gross mark-to-market gain (asset position) on these trading contracts of $14.4 million and a gross mark-to-market loss (liability position) of $17.9 million, with net mark-to-market losses of $3.5 million. The mark-to-market valuation is recognized in earnings each period. In addition, the Company enters into forward physical contracts. The Company generally accounts for these derivative financial instruments as normal sales and purchases as defined by SFAS 133, as amended. These contracts are typically sales of the Company's electric capacity in excess of its jurisdictional needs, including reserves, or purchases of jurisdictional needs, including reserves, when resource shortfalls exist. The Company from time to time makes forward purchases to serve its jurisdictional needs when the cost of purchased power is less than the incremental cost of its generation. At March 31, 2001, the Company had open forward positions classified as normal sales of electricity of $383.8 million and normal purchases of electricity of $221.7 million. 14 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (4) Financial Instruments (Continued) The Company designated certain forward purchase contracts for electricity as cash flow hedges. The Company's designated cash flow hedges at March 31, 2001, were forward purchase contracts for the purchase of electric power for forecasted jurisdictional use during planned outages in 2001 and certain forecasted sales. The hedged risks associated with these instruments are the changes in cash flows related to forecasted purchase of electricity due to changes in the price of electricity on the spot market. Assessment of hedge effectiveness will be based on the changes in the forward price of electricity. There was no hedge ineffectiveness recognized in the three months ended March 31, 2001. It is a common practice within the electric utility industry to net offsetting purchase and sales contracts between two or more counterparties to facilitate transmission. This is commonly referred to as a "book-out." Whether a book-out occurs is dependant on a number of factors, including agreement by all parties in the chain of the transaction, efficiency of the transaction flow, congestion on the electrical transmission system, and system reliability issues. Book-outs do not occur until a short time before the electricity is due to be physically delivered, no matter when the original contracts in the chain were entered into, and have no legal standing should one of the parties in the chain default. The Derivatives Implementation Group ("DIG") of the FASB has reached a tentative conclusion that all contracts for the sale or purchase of electricity that are subject to being booked out, whether that is the intent of the counterparties or not, do not qualify for the normal sale or normal purchase exception. The conclusion is tentative until formally cleared by the FASB and incorporated in an FASB staff implementation guide. If the conclusion of the DIG is accepted by the FASB, the Company may be required to mark-to-market its transactions that it has classified as normal purchases and normal sales. The Company is unable to determine the impact of this conclusion. The Company's wholesale power marketing operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. The Company's value-at-risk calculation considers this exposure (see Item 3 "Quantitative and Qualitative Disclosure About Market Risk"). Hedge of Trust Assets In February 2001, the Company terminated certain financial derivatives based on the Standard & Poor's ("S&P") 500 Index. These instruments were used to limit potential loss on investments for nuclear decommissioning, executive retirement and retiree medical benefits due to adverse market fluctuations. The Company recognized a realized gain of $0.5 million (pretax) as a result. Previously, the Company had marked-to-market the financial instruments to match the hedged investment activity. 15 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (5) Earnings Per Share In accordance with SFAS No. 128, Earnings per Share, dual presentation of basic and diluted earnings per share has been presented in the Consolidated Statements of Earnings. The following reconciliation illustrates the impact on the share amounts of potential common shares and the earnings per share amounts for March 31 (in thousands except per share amounts): Three Months Ended March 31, 2001 2000 ----------- ----------- Basic: Net Earnings from Continuing Operations............... $ 63,552 $ 21,952 ----------- ----------- Net Earnings.......................................... 63,552 21,952 Preferred Stock Dividend Requirements................. 146 146 ----------- ----------- Net Earnings Applicable to Common Stock............... $ 63,406 $ 21,806 =========== =========== Average Number of Common Shares Outstanding........... 39,118 39,973 =========== =========== Net Earnings per Common Share (Basic)................. $ 1.62 $ 0.55 =========== =========== Diluted: Net Earnings Applicable to Common Stock Used in basic calculation........................... $ 63,406 $ 21,806 =========== =========== Average Number of Common Shares Outstanding........... 39,118 39,973 Diluted effect of common stock equivalents (a)........ 481 29 ----------- ----------- Average common and common equivalent shares Outstanding......................................... 39,599 40,002 =========== =========== Net Earnings per Share of Common Stock (Diluted)...... $ 1.60 $ 0.55 =========== =========== (a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of 186,736 for the three months ended March 31, 2000. There were no anti-dilutive common stock equivalents in 2001. (6) Commitments and Contingencies Construction Commitment The Company has committed to purchase combustion turbines for $126 million. The turbines are for planned power generation plants with an estimated cost of approximately $245 million for which contracts have not been finalized. The planned plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. 16 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) Commitments and Contingencies (Continued) Natural Gas Explosion On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. At least one passerby received minor injuries from the blast. Several claims for property and business interruption damages have been received by the Company. The cause of the leak is unknown and the Company is conducting an investigation into the explosion. No lawsuits against the Company have yet been served on the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur. There can be no assurance that the outcome of this matter will not have a material impact on the results of operations and financial position of the Company. Implementation of Customer Billing System On November 30, 1998, the Company implemented a new customer billing system. Due to a significant number of problems associated with the implementation of the new billing system, the Company was unable to generate appropriate bills for all its customers through the first quarter of 1999 and was unable to analyze delinquent accounts until November 1999. As a result of the delay of normal collection activities, the Company incurred a significant increase in delinquent accounts, many of which occurred with customers that no longer have active accounts with the Company. The Company continued its analysis and collection efforts of its delinquent accounts resulting from the problems associated with the implementation of the new customer billing system throughout 2000 and identified additional bad debt exposure. As a result, the Company significantly increased its estimated bad debt costs throughout 1999 and 2000. By the end of 2000, the Company completed its analysis of its delinquent accounts and resumed its normal collection procedures. As a result, the Company determined that $13.5 million of customer receivables would not be collectible. Based upon information available at March 31, 2001, the Company believes the allowance for doubtful accounts of $11.0 million is adequate for management's estimate of potential uncollectible accounts. In addition, due to the significantly higher natural gas prices experienced in November and December 2000, the Company increased its bad debt expense by approximately $1 million for the three months ended March 31, 2001 and $2 million for the year ended December 31, 2000 in anticipation of higher than normal delinquency rates. The Company expects this trend to continue as long as natural gas prices remain higher than historical levels. 17 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) Commitments and Contingencies (Continued) The following is a summary of the allowance for doubtful accounts during the three months ended March 31, 2001 and the year ended December 31, 2000:
March 31, December 31, 2001 2000 --------------- --------------- Allowance for doubtful accounts, beginning of year................................................... $ 8,963 $12,504 Bad debt expense............................................ 3,434 9,980 Less: Write off (adjustments) of uncollectible accounts.... 1,399 13,521 ------------- -------------- Allowance for doubtful accounts, end of year ............... $10,998 $ 8,963 ============= ==============
PVNGS Liability and Insurance Matters The PVNGS 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 primary liability insurance limit, the Company could be assessed retrospective 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 reactor per incident. Based upon the Company's 10.2% interest in the three PVNGS units, the Company's maximum potential assessment per incident for all three units is approximately $27.0 million, with an annual payment limitation of $3 million per incident. If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue raising measures on the nuclear industry to pay claims. The United States Nuclear Regulatory Commission and Congress are reviewing the related laws. The Company cannot predict whether or not Congress will change the law. However, certain changes could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by the lessors. The PVNGS participants maintain "all-risk" (including nuclear hazards) insurance for nuclear property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion as of January 1, 2001. The Company is a member of an industry mutual insurer which provides both the "all-risk" and increased cost of generation insurance to the Company. In the event of adverse losses experienced by this insurer, the Company is subject to an assessment. The Company's maximum share of any assessment is approximately $2.3 million per year. PVNGS Decommissioning Funding The Company has a program for funding its share of decommissioning costs for PVNGS. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. The results of the 1998 decommissioning cost study indicated that the Company's share of the PVNGS 18 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) Commitments and Contingencies (continued) decommissioning costs excluding spent fuel disposal will be approximately $179.9 million (in 2001 dollars). The estimated market value of the trusts at the end of March 31, 2001 was approximately $51 million. Nuclear Spent Fuel and Waste Disposal Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "Waste Act"), the United States Department of Energy ("DOE") is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. Under the Waste Act, DOE was to develop the facilities necessary for the storage and disposal of spent nuclear fuel and to have the first such facility in operation by 1998. DOE has announced that such a repository now cannot be completed before 2010. The operator of PVNGS has capacity in existing fuel storage pools at PVNGS which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of PVNGS through 2002, and believes it could augment that storage with the new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. The Company currently estimates that it will incur approximately $41 million (in 1998 dollars) over the life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. The Company accrues these costs as a component of fuel expense, meaning the charges are accrued as the fuel is burned. The operator of PVNGS currently believes that spent fuel storage or disposal methods will be available for use by PVNGS to allow its continued operation beyond 2002. Other There are various claims and lawsuits pending against the Company and certain of its subsidiaries. The Company is also subject to Federal, state and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with business operations. It is not possible at this time for the Company to determine fully the effect of all litigation on its consolidated financial statements. However, the Company has recorded a liability where the litigation effects can be estimated and where an outcome is considered probable. The Company does not expect that any known lawsuits, environmental costs and commitments will have a material adverse effect on its financial condition or results of operations. (7) Environmental Issues The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred. Sources of potential 19 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (7) Environmental Issues (Continued) environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes. The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company, records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). The Company's recorded estimated minimum liability to remediate its identified sites is $6.8 million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $11.6 million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company. In 2001, the Company anticipates spending $1.4 million for remediation and $0.7 million for control and prevention. The majority of the March 31, 2001 environmental liability is expected to be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company. (8) Proposed Acquisition On November 9, 2000, the Company and Western Resources, Inc. (Western Resources) announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. Under the terms of the agreement, the Company and Western Resources, whose utility operations consist of its Kansas Power and Light division and Kansas Gas and Electric subsidiary, will both become subsidiaries of a new holding company to be named at a future date. Prior to the consummation of this combination, Western Resources will reorganize all of its non-utility assets, including its 85 percent stake in Protection One and its 45 percent investment in ONEOK, into Westar Industries which will be spun off to Western Resources' shareholders, prior to the acquisition of Western's utility businesses by the Company. 20 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (8) Proposed Acquisition (Continued) The new holding company will issue 55 million of its shares, subject to adjustment, to Western Resources' shareholders and Westar Industries. Before any adjustments, the new company will have approximately 94 million shares outstanding, of which approximately 41 percent will be owned by former Company shareholders and 59 percent will be owned by former Western Resources shareholders and Westar Industries. In the transaction, each Company share will be exchanged on a one-for-one basis for shares in the new holding company. Each Western Resources share will be exchanged for a fraction of a share of the new company. This exchange ratio will be finalized at closing, depending on the impact of certain adjustments to the transaction consideration. Under the terms of the acquisition agreement, Western Resources and Westar have been given an incentive to reduce Western Resources net debt balance prior to the consummation of the transaction by selling non-utility assets or through other debt reduction activities. The agreement contains a mechanism to adjust the transaction consideration based on certain activities not affecting the utility operations, which increase the equity of the utility. In addition, Westar Industries has the option of making equity infusions into Western Resources that will be used to reduce the utility's net debt balance prior to closing. Up to $407 million of such equity infusions may be used to purchase additional new holding company common and convertible preferred stock. The effect of these activities would be to increase the number of new holding company shares to be issued to all Western Resources shareholders (including Westar Industries) in the transaction. In February 2001, Westar purchased 14.4 million Western Resources common shares at $24.358 per share (based on a 20 day look-back price at February 28, 2001) at an aggregate price of $350 million. As a result of this equity contribution, the acquisition consideration may be adjusted to include an additional 4.3 million shares of the new holding company depending on the impact of future transactions between Western Resources and Westar. The transaction will be accounted for as a reverse acquisition by the Company as Western Resources shareholders will receive the majority of the voting interests in the new holding company. For accounting purposes Western Resources will be treated as the acquiring entity. Accordingly, all of the assets and liabilities of the Company will be recorded at fair value in the business combination as required by the purchase method of accounting. In addition, the operations of the Company will be reflected in the reported results of the combined company only from the date of acquisition. Based on the volume weighted average closing price of the Company's common stock over the two days prior and two days subsequent to the announcement of the transaction of $24.149 per share, the indicated equity consideration of the transaction was approximately $945 million, excluding the potential issuance of additional shares discussed above. There is approximately $2.9 billion of existing Western Resources debt giving the transaction an aggregate enterprise value of approximately $3.8 billion. There are plans for the new holding company to reduce and refinance a portion of the Western Resources debt. 21 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (8) Proposed Acquisition (Continued) The successful spin-off of Westar Industries from Western Resources is required prior to the consummation of the transaction. The transaction is also conditioned upon, among other things, approvals from both companies' shareholders and customary regulatory approvals from the Kansas Corporation Commission ("KCC"), the PRC, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Federal Communications Commission and either the Federal Trade Commission or the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse regulatory outcome related to other actions involving rate making or approval of regulatory plans may affect the transaction. The new holding company expects to register as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. Management believes that the above mentioned approvals are expected to be obtained over the next 12 to 15 months, however should such approvals not be obtained, final consummation of the proposed acquisition cannot occur. (9) New and Proposed Accounting Standards Decommissioning: The Staff of the Securities and Exchange Commission ("SEC") has questioned certain of the current accounting practices of the electric industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In February 2000, the Financial Accounting Standards Board ("FASB") issued an exposure draft regarding Accounting for Obligations Associated with the Retirement of Long-Lived Assets ("Exposure Draft"). The Exposure Draft requires the recognition of a liability for an asset retirement obligation at fair value. In addition, present value techniques used to calculate the liability must use a credit adjusted risk-free rate. Subsequent remeasures of the liability would be recognized using an allocation approach. The Company has not yet determined the impact of the Exposure Draft. 22 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS All references to the Company refer to Public Service Company of New Mexico or its proposed successor holding company PNM Resources, Inc. (see "Restructuring the Electric Utility Industry" below). The following is management's assessment of the Company's financial condition and the significant factors affecting the results of operations. This discussion should be read in conjunction with the Company's consolidated financial statements and Part I, Item 3. - Legal Proceedings. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. OVERVIEW The Company is a public utility primarily engaged in the generation, transmission, distribution and sale of electricity and in the transmission, distribution and sale of natural gas within the State of New Mexico. In addition, in pursuing new business opportunities, the Company provides energy and utility related product offerings through its wholly-owned subsidiary, Avistar. As it currently operates, the Company's principal business segments are Utility Operations, which include the Electric Product Offering ("Electric") and the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations ("Generation and Trading"). The Electric Product Offering consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment for accounting purposes due to its immateriality, and for purposes of this discussion, it is combined with the distribution product offering. UTILITY OPERATIONS Electric The Company provides jurisdictional retail electric service to a large area of north central New Mexico, including the City of Albuquerque and the City of Santa Fe, and certain other areas of New Mexico. Retail sale revenues, which include distribution and transmission, were $134.5 million and $126.1 million for the three months ended March 31, 2001 and March 31, 2000 respectively. The Company owns or leases 2,781 circuit miles of transmission lines, interconnected with other utilities east into Texas, west into Arizona, and north into Colorado and Utah. Due to rapid load growth in recent years, most of the capacity on this transmission system is fully committed and there is no additional access available on a firm commitment basis. These factors, together with significant physical constraints in the system, limit the ability to wheel power into the Company's service area from outside the state. 23 Gas The Company's Gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe. The Company's gas customer base includes both sales-service customers and transportation-service customers. Sales-service customers purchase natural gas and receive transportation and delivery services from the Company for which the Company receives both cost-of-gas and cost-of-service revenues. Additionally, the Company makes occasional gas sales to off-system customers. Off-system sales deliveries generally occur at interstate pipeline interconnects with the Company's system. Transportation-service customers, who procure gas independently of the Company and contract with the Company for transportation and related services, provide the Company with cost-of-service revenues only. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. These contracts are generally sufficient to meet the Company peak-day demand. The following table shows gas throughput by customer class: GAS THROUGHPUT (Thousands of decatherms) Three Months Ended March 31, 2001 2000 ---------- ----------- Residential............................ 12,481 11,121 Commercial............................. 4,207 3,477 Industrial............................. 1,980 224 Transportation*........................ 9,178 9,011 Other.................................. 1,667 1,932 ---------- ----------- 29,513 25,765 ========== =========== The following table shows gas revenues by customer: GAS REVENUES (Thousands of dollars) Three Months Ended March 31, 2001 2000 ------------ ------------ Residential........................... $121,590 $62,851 Commercial............................ 36,798 16,615 Industrial............................ 13,537 794 Transportation*....................... 4,002 3,984 Other................................. 16,009 10,301 ------------ ------------ $191,936 $94,545 ============ ============ *Customer-owned gas. 24 GENERATION AND TRADING OPERATIONS The Company's Generation and Trading Operations serve four principal markets. Sales to the Company's Utility Operations to cover jurisdictional electric demand and sales to firm-requirements wholesale customers, sometimes referred to collectively as "system" sales, comprise two of these markets. The third market consists of other contracted sales to third parties for which the Generation and Trading Operations commit to deliver a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time. The fourth market consists of economy energy sales made on an hourly basis at fluctuating, spot-market rates. Sales to the third and fourth markets are sometimes referred to collectively as "off-system" sales. Off-system sales include the Company's energy trading activities. The following table shows sales by customer class: GENERATION AND TRADING SALES BY MARKET (Megawatt hours) Three Months Ended March 31, 2001 2000 --------------- ---------------- Intersegment sales...................... 1,718,565 1,655,150 Firm-requirements wholesale............. 122,786 47,921 Other contracted off-system sales....... 1,901,261 2,042,998 Economy energy sales.................... 1,134,084 1,272,668 --------------- ---------------- 4,876,696 5,018,737 =============== ================ The following table shows revenues by customer class: GENERATION AND TRADING REVENUES BY MARKET (Thousands of dollars) Three Months Ended March 31, 2001 2000 --------------- ---------------- Intersegment revenues................... $ 80,917 $ 75,822 Firm-requirements wholesale............. 3,128 1,736 Other contracted off-system revenues.... 197,892 62,807 Economy energy revenues................. 209,641 35,714 Other................................... (413) 219 --------------- ---------------- $ 491,165 $ 176,298 =============== ================ The Generation and Trading Operations have ownership interests in certain generating facilities located in New Mexico, including the San Juan Generating Station, a coal fired unit, and the Four Corners Power Plant, a coal fired unit. In addition, the Company has ownership and leasehold interests in Palo Verde Nuclear Generating Station ("PVNGS") located in Arizona. These generation assets are used to supply retail and wholesale customers. The 25 Generation and Trading Operations also own Reeves Generating Station, a gas and oil fired unit and Las Vegas Generating Station, a gas and oil fired unit, that are used for reliability purposes or to generate electricity for the wholesale market during certain demand periods in the Generation and Trading Operations' wholesale power markets. As of December 31, 2000, the total net generation capacity of facilities owned or leased by the Generation and Trading Operations was 1,653 MW. On July 13, 2000, the Company commenced a 20 year power purchase agreement for an additional 132 MW for the rights to all output of a new gas fired generating plant. In addition to its generation capacity, the Generation and Trading Operations purchase power in the open market. AVISTAR The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a New Mexico corporation and is currently engaged in certain unregulated, non-utility businesses, including energy and utility-related services previously operated by the Company. The PRC authorized the Company to invest $50 million in equity in Avistar and to enter into a reciprocal loan agreement for up to $30 million. The Company has currently invested $35 million in Avistar. ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS On November 9, 2000, the Company and Western Resources, Inc. ("Western Resources") announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources' electric utility operations in a tax-free, stock-for-stock transaction. The new combined company will serve over one million retail electric customers and 435,000 retail gas customers in New Mexico and Kansas and will have generating capacity of more than 7,000 MW. The transaction exceeds the Company's stated goal of doubling its generation capacity and tripling its power sales more than three years ahead of schedule. However, the Company intends to proceed with plans to add generation capacity to serve Western wholesale markets. The transaction will also make the new company a leading energy supplier in the Western and Midwestern wholesale markets. The transaction will provide the Company with the opportunity to accelerate its proven growth strategy by developing a similar niche product, asset-backed wholesale power marketing strategy at Western Resources. The strategic nature of the acquisition is based upon revenue-growth. As a result, the Company expects modest cost savings although cost reduction will be one aspect of the integration effort. At present the Company does not anticipate significant cost savings as a result of involuntary workforce reductions. The new holding company will seek to minimize any workforce effects through reduced hiring, attrition, and other appropriate measures. All existing labor agreements will be honored. The transaction is expected to close promptly after all of the conditions to its consummation are fulfilled, including the spin off to Western Resources' shareholders of Western Resources' non-utility businesses, approval from both companies' shareholders and customary regulatory approvals. (See "Other Issues Facing The Company - Acquisition of Western Resources Electric Operations" below). 26 RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for corporate separation of certain deregulated activities from activities regulated by the PRC. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The amendments require that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of the regulated and deregulated activities, by July 1, 2001. In April 2001, the Company filed its application for the creation of a holding company. Hearings on the matter occurred in mid May. Previously, in June 2000, shareholders approved the mandatory share exchange necessary to implement a holding company structure. In April 2001, the Company's Board of Directors amended the articles of incorporation of the proposed holding company to rename the holding company "PNM Resources, Inc." (PNM Resources). The holding company was originally approved by shareholders last year as Manzano Corporation. The Company is unable to predict the outcome of its application and whether or not the holding company proposed will be approved by the PRC with acceptable conditions. In addition, the amendments to the Restructuring Act allow utilities to engage in unregulated power generation business activities until corporate separation is implemented. The Company believes that its ability to form a new holding company and expand generation assets in an unregulated environment will give it the flexibility it needs to pursue its strategic plan despite the delay in customer choice and corporate separation. The Company is unable to predict the form its restructuring will take under the delayed implementation of customer choice. The formulation of a restructuring plan will be dependent on future business conditions at the expected time customer choice is implemented (See "Other Issues Facing The Company - Recovery of Certain Costs Under The Restructuring Act" below). COMPETITIVE STRATEGY The Restructuring Act, as amended, allows the Company and other utilities to build or acquire new generating plants for merchant purposes in the interim with minimum regulatory approvals. These new plants will be excluded from utility rates under the provisions of the bill. The cost of new unregulated utility generation resources will serve as a cap for ratemaking purposes, or the price of new resources needed to serve retail customers until customer choice and corporate restructuring is implemented. In addition, the New Mexico Legislature passed and the Governor signed, an amendment to the Public Utility Act requiring the PRC to act on siting applications for certain generating plants and transmission lines within six months. Transmission applications that are environmentally sensitive would be allowed an additional ten months. 27 The Company's Generation and Trading Operations have contributed significant earnings to the Company in recent years as a result of increased off-system sales including its energy trading activities. The Company plans to expand its wholesale energy trading functions which could include an expansion of its generation portfolio as well as expanding trading operations. The Company continuously evaluates its physical asset acquisition strategies to ensure an optimal mix of base-load generation, peaking generation and purchased power in its power portfolio. In addition to the continued energy trading activities, the Company will further focus on opportunities in the market place where excess capacity is disappearing and mid- to long-term market demands are growing. The Company's current business plan includes a 300% increase in sales and a doubling of its generating capacity, excluding the effects of the Western Resources transaction, through the construction or acquisition of additional power generation assets in its surrounding region of operations over the next five to seven years. The Company will continue to pursue growth in its generation portfolio and intends to spend approximately $800 million over the next five years to achieve generation portfolio growth. Such growth will be dependent upon the Company's ability to generate funds for the Company's expansion. The Company currently has $161.3 million of available cash as well as adequate borrowing capacity to fund the expansion program. There can be no assurance that investments in new unregulated generation facilities, will be successful or, if unsuccessful, that they will not have a direct or indirect adverse effect on the Company. At the Federal level, there have been a number of proposals on electric restructuring being considered with no concrete timing for definitive actions. None of these proposals have been acted upon by Congress. Issues such as stranded cost recovery, market power, utility regulation reform, the role of states, subsidies, consumer protections and environmental concerns are expected to be reintroduced if not acted upon in the current Congressional session. In addition, the FERC has stated that if Congress mandates electric retail access, it should leave the details of the program to the states with the FERC having the authority to order the necessary transmission access for the delivery of power for the states' retail access programs. Recent federal actions have focused on the energy crisis in California with bills being introduced to require caps on wholesale prices. In addition, the Senate Banking Committee has voted 19-1 to repeal the Public Utility Holding Company Act. Although it is unable to predict the ultimate outcome of retail competition in New Mexico, the Company has been and will continue to be active at both the state and Federal levels in the public policy debates on the restructuring of the electric utility industry. The Company will continue to work with customers, regulators, legislators and other interested parties to find solutions that bring benefits from competition while recognizing the importance of reimbursing utilities for past commitments. 28 RESULTS OF OPERATIONS The following discussion is based on the financial information presented in Footnote 1 of the Consolidated Financial Statements - Nature of Business and Segment Information. The table below sets forth the operating results as percentages of total operating revenues for each business segment. Three Months Ended March 31, 2001
Utility --------------------------------------------------- Generation Electric Gas and Trading ------------------------- ------------------------ --------------- Operating revenues: External customers................... $134,346 99.87% $191,936 100.00% $410,248 83.53% Intersegment revenues................ 177 0.13 - 0.00 80,917 16.47 ----------- ---------- ----------- --------- ---------- --------- Total revenues....................... 134,523 100.00 191,936 100.00 491,165 100.00 ----------- ---------- ----------- --------- ---------- --------- Cost of energy sold.................... 1,560 1.16 148,472 77.35 347,066 70.66 Intersegment purchases................. 80,917 60.15 - 0.00 177 0.04 ----------- ---------- ----------- --------- ---------- --------- Total fuel costs..................... 82,477 61.31 148,472 77.35 347,243 70.70 ----------- ---------- ----------- --------- ---------- --------- Gross margin........................... 52,046 38.69 43,464 22.65 143,922 29.30 ----------- ---------- ----------- --------- ---------- --------- Administrative and other costs......... 9,735 7.24 12,199 6.36 4,960 1.01 Energy production costs................ 310 0.23 431 0.22 34,284 6.98 Depreciation and amortization.......... 8,025 5.97 5,290 2.76 10,895 2.22 Transmission and distribution costs.... 8,107 6.03 7,056 3.68 113 0.02 Taxes other than income taxes.......... 2,527 1.88 1,596 0.83 1,921 0.39 Income taxes........................... 7,549 5.61 5,505 2.87 32,722 6.66 ----------- ---------- ----------- --------- ---------- --------- Total non-fuel operating expenses.... $36,253 26.95 $32,077 16.71 $84,895 17.28 ----------- ---------- ----------- --------- ---------- --------- Operating income....................... 15,793 11.74% 11,387 5.93% 59,027 12.02% ----------- ---------- ----------- --------- ---------- ---------
Three Months Ended March 31, 2000
Utility --------------------------------------------- Generation Electric Gas and Trading ---------------------- --------------------- --------------------- Operating revenues: External customers................... $125,922 99.86% $94,545 100.00% $100,475 56.99% Intersegment revenues................ 177 0.14 - 0.00 75,822 43.01 ---------- ----------- ---------- --------- ----------- --------- Total revenues....................... 126,099 100.00 94,545 100.00 176,297 100.00 ---------- ----------- ---------- --------- ----------- --------- Cost of energy sold.................... 1,133 0.90 57,833 61.17 108,757 61.69 Intersegment purchases................. 75,822 60.13 - 0.00 177 0.10 ---------- ----------- ---------- --------- ----------- --------- Total fuel costs..................... 76,955 61.03 57,833 61.17 108,934 61.79 ---------- ----------- ---------- --------- ----------- --------- Gross margin........................... 49,144 38.97 36,712 38.83 67,363 38.21 ---------- ----------- ---------- --------- ----------- --------- Administrative and other costs......... 9,077 7.20 9,913 10.48 4,295 2.44 Energy production costs................ 416 0.33 368 0.39 34,858 19.77 Depreciation and amortization.......... 8,326 6.60 5,366 5.68 10,312 5.85 Transmission and distribution costs.... 7,863 6.24 7,401 7.83 8 0.00 Taxes other than income taxes.......... 3,330 2.64 1,975 2.09 2,767 1.57 Income taxes........................... 6,099 4.84 3,571 3.78 1,428 0.81 ---------- ----------- ---------- --------- ----------- --------- Total non-fuel operating expenses.... 35,111 27.84 28,594 30.24 53,668 30.44 ---------- ----------- ---------- --------- ----------- --------- Operating income....................... $14,033 11.13% $ 8,118 8.59% $ 13,695 7.77% ---------- ----------- ---------- --------- ----------- ---------
29 Three Months Ended March 31, 2001 Compared to Three Months Ended March 31, 2000 UTILITY OPERATIONS Electric - Operating revenues increased $8.4 million (6.7%) for the period to $134.5 million. Contributing to the increase was an increase in retail electricity delivery of 1.72 million MWh in 2001 compared to 1.66 million MWh delivered in the prior year period, a 3.8% improvement which increased revenues $4.8 million period-over-period. This increased volume was the result of a weather-driven increase in consumption and load growth. In addition, transmission wheeling revenues increased $2.1 million as a result of additional capacity sales and other revenues increased $1.4 million primarily for new property leasing for telecommunication systems. The gross margin, or operating revenues minus cost of energy sold, increased $2.9 million but declined slightly as a percentage of revenues. This dollar increase reflects the increased energy sales and the telecommunication property leasing, partially offset by an increase in intersegment transfer pricing. Gross margin as a percentage of revenues declined from 39.0% to 38.7%. The decline in gross margin percentage is primarily a result of the increase in intersegment transfer pricing. The Company's Generation and Trading Operations exclusively provide power to Electric. Intersegment purchases for the Generation and Trading Operations are priced using internally developed transfer pricing and are not based on market rates. Customer rates for electric service are set by the PRC based on the recovery of the cost of power production and a rate of return that includes certain generation assets that are part of Generation and Trading Operations, among other things. Administrative and general costs increased $0.7 million (7.2%) for the period. This increase is largely due to increased pension and benefits expense resulting primarily from lower than expected investment returns on related plan assets. As a percentage of revenues, administrative and other costs remained constant at 7.2% for the three months ended March 31, 2001 and 2000, respectively, as a result of cost control measures. Taxes other than income decreased $0.8 million (24.1%) due to higher tax liabilities in the prior year period as a result of audits by certain tax authorities. Taxes other than income as a percentage of revenues decreased to 1.9% from 2.6%. Gas - Operating revenues increased $97.4 million (103.0%) for the period to $191.9 million. This increase was driven by an 80.2% increase in the average rate charge per decatherm due to high wholesale gas prices in the first quarter of 2001 as a result of increased market demand for natural gas, a 14.6% volume increase and a gas rate increase which became effective October 30, 2000. Residential and commercial customers volume increased 14.3% due to a colder winter during 2001. Customer volume, other than residential and commercial, increased 14.8%. This growth was primarily attributed to industrial customers such as the Company's Generation and Trading Operations whose increased demand was driven by the strong power market prevailing in the Western United States during the first quarter of 2001. In the second quarter of 2001, the Company's Generation and Trading operations began procuring its gas supply independent of the Company and contracting with the Company only for transportation services. 30 The gross margin, or operating revenues minus cost of energy sold, increased $6.8 million (18.4%). This increase is due to the rate increase and higher distribution volumes on which the Company earns cost of service revenues. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, the increase in gas prices driving increased cost of sales revenues does not have an impact on the Company's gross margin or earnings. Administrative and general costs increased $2.3 million (23.1%). This increase is due largely to increased pension and benefits expense as well as increased bad debt costs of $1.3 million recognized in anticipation of a higher than normal delinquency rate driven by the significantly higher natural gas prices experienced in the 2000-2001 heating season. This trend is similar to historic collection trends associated with past natural gas price spikes. GENERATION AND TRADING OPERATIONS Operating revenues grew $314.9 million (178.6%) for the period to $491.2 million. This increase in wholesale electricity sales reflects strong regional wholesale electric prices caused by limited power generation capacity, increased natural gas prices and the power supply/demand imbalance in the Western United States. These factors contributed to unusually high wholesale prices which the Company does not believe to be sustainable in the long-term, but may continue to affect markets in 2001 and 2002. In addition, these factors have led to an extremely volatile wholesale electric power market with significant risk (see Other Issues Facing the Company - Western United States Wholesale Power Market). The Company delivered wholesale (bulk) power of 3.2 million MWh of electricity this period compared to 3.4 million MWh delivered in the prior period, a decrease of 6.1%. The MWh decrease is attributable to decreased trading activity during the period. Lower trading volumes are related to the volatile market and the Company's risk management policies, which limit certain transactions in this environment. The majority of the wholesale sales, in the current quarter, are from power purchased for resale. Exposure to adverse market moves is limited through an asset backed strategy, whereby the Company's aggregate net open position is covered by its generation resources, primarily generation which has been excluded from retail rates. This strategy, along with the Company's credit policies, limit the Company's wholesale sales in a volatile market. Wholesale revenues from third-party customers increased from $100.5 million to $410.2 million, a 308.3% increase. The increase was largely price driven. The gross margin, or operating revenues minus cost of energy sold, increased $76.6 million (113.7%). Higher margins were partially offset by $13.2 million of allowances against revenues associated with the Company's assessment of credit and market risk in the wholesale market (see Other Issues Facing The Company - Western United States Wholesale Power Market) and unrealized mark-to-market losses of $3.6 million which the Company recognized relating to its power trading contracts (see Note 4 of the Notes to Consolidated Financial Statements). These items were recorded as revenue adjustments. Gross margin as a percentage of revenues decreased from 38.2% to 29.3% reflecting higher cost of energy purchased. Administrative and general costs increased $0.7 million (15.5%) for the period. This increase is primarily due to increased pension and benefits expense. As a percentage of revenues, administrative and other costs decreased to 1.0% from 2.4% for the three months ended March 31, 2001 and 2000, respectively as a result of increased revenues and cost control measures. 31 Energy production costs decreased $0.6 million (1.6%) for the year. The decrease is due to higher maintenance costs in 2000 resulting from scheduled and unscheduled outages at San Juan Unit 3 and Four Corners Unit 4. As a percentage of revenues, energy production costs decreased from 19.8% to 7.0%. The decrease is primarily due to the significant increase in energy revenues and cost cutting measures. Depreciation and amortization increased $0.6 million (5.7%) for the period due to a higher depreciable plant base. Depreciation and amortization as a percentage of revenues decreased from 5.7% to 2.2% due to the increase in energy revenues. Taxes other than income decreased $0.8 million (30.6%) due to higher tax liabilities in the prior year period as a result of audits by certain tax authorities. Taxes other than income as a percentage of revenues decreased from 1.6% to 0.4% as a result of the increase in energy revenues. UNREGULATED BUSINESSES Avistar continued to experience lower business volumes resulting from slow developing markets associated with its new product offerings. Operating losses for Avistar decreased from $1.2 million in the prior year period to $0.9 million in the current year period due to higher interest income on cash balances. CONSOLIDATED Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, increased $4.0 million for the period. This increase was due to higher legal costs associated with increased business activity and expansion planning and bonus accruals due to increased earnings, partially offset by reorganizational costs that were incurred in 2000 in anticipation of separating utility operations under the Restructuring Act, which has since been delayed (see "Restructuring The Electric Utility Industry"). Other income and deductions, net of taxes, decreased $4.9 million for the period to $2.6 million primarily due to valuation losses of $8.3 million (pre-tax) related to investments in two energy-related technology companies. The current year also had decreased mark-to-market fair values on the corporate hedge and the PVNGS decommissioning trust assets (see Note 4 to the Consolidated Financial Statements) and costs related to the Company's proposed acquisition of Western Resources' electric utility operations. The Company expects to continue to incur acquisition related costs in 2001 and beyond. The Company's consolidated income tax expense was $42.6 million in the three months ended March 31, 2001, an increase of $29.9 million for the period. The Company's income tax effective rate for the three months ended March 31, 2001 was 40.15%. Included in the Company's 2001 taxable income are certain non-deductible costs related to the Company's acquisition of Western Resources' electric utility operations. Excluding these costs, the Company's effective tax rate was 39.0%. The Company's effective tax rate for the three months ended March 31, 2000 was 36.7%. The increase in the rate was primarily due to an increase in the depreciation of flow-through items. 32 The Company's net earnings for the three months ended March 31, 2001 were $63.6 million, a 189.5% increase. Excluding the Western Resources' acquisition costs and the related impact on the effective tax rate ("2001 Special Items"), the Company's net earnings were $65.4 million. Net earnings for the three months ended March 31, 2000 were $22.0 million. Net earnings from continuing operations excluding the 2001 Special Items increased from $22.0 million in 2000 to $65.4 million in 2001. Earnings per share on a diluted basis were $1.65 (excluding the 2001 Special Items) for the three months ended March 31, 2001 compared to $0.55 for the three months ended March 31, 2000. Diluted weighted average shares outstanding were 39.6 million and 40.0 million in 2001 and 2000, respectively. The decrease reflects the common stock repurchase program in 2000. Net earnings per share from continuing operations primarily increased due to expansion of the Company's wholesale energy trading activities and the common stock repurchase program. FUTURE EXPECTATIONS On April 18, 2001, the Company announced that it was revising its 2001 earnings expectations. The Company now expects full year 2001 earnings to be significantly higher than previously forecasted. The continuing volatility in the wholesale power market makes further specific earnings guidance for the year unrealistic. While forecasting a substantial increase in earnings for 2001 and 2002, management does not believe those gains are sustainable over the longer term. As conservation measures take effect in California and throughout the west, and as new generation comes on-line over the next two to three years, management expects that prices will stabilize at somewhat lower levels. Looking at the forward prices for power and natural gas and the Company's market positioning and base earnings ability, management believes that its earnings are sustainable at around $3.50 a share. Currently high wholesale prices have the potential to raise earnings substantially above that level in the near term but management believes that earnings at these higher levels are not sustainable over the long run. As the Company adds new generation resources, it is expected that earnings will trend upwards, although at a rate less than the 10 percent annual growth rate previously targeted by management due to the higher base earnings the Company has forecasted. The Company's strategic plan to double generation will provide electric wholesale volume growth beginning in 2002 and in the later years of the forecast. These expectations are all stand-alone forecasts and do not take into account the likely impact of the proposed acquisition of Western Resources. The Company has previously stated that based on assumptions at the time it expected its acquisition of Western Resources' electric utility assets to be immediately accretive to earnings. Since that time, the Company's earnings expectations for its stand-alone operations have increased significantly while Western Resources reported earnings have declined for the year ended December 31, 2000 as compared to the year ended December 31, 1999. In addition, Western Resources' earnings outlook may also be influenced by the outcome of its electric utility rate case (see "Other Issues Facing the Company - Acquisition of Western Resources Electric Operations"). Calculations regarding accretion/dilution are subject to many key assumptions with a high degree of volatility, including assumptions regarding future earnings for both companies, which in turn are subject to assumptions regarding 33 rate case decisions, terms and conditions of regulatory approvals for the transactions and market conditions. Based on updated information regarding the Company's earnings outlook and Western Resources historic results, the Company's previous forecast of the combined company would now show earnings dilution. Whether or not the combination would be dilutive or accretive is highly dependent on future events that cannot be predicted at this time, including the results of the pending Western Resources rate case and terms and conditions that might be imposed as a result of the applications for regulatory approvals. Management's revised expectations are based on its current view of the wholesale power market. Management's previous expectations with regard to the Company's utility operations and non-fuel operating and maintenance expenses remain largely unchanged. Management's expectations for 2001 assume retail sales growth will continue at rates comparable to what was experienced in 2000 and the full realization of the favorable outcome of the two gas rate cases settled in August of 2000. Expenses are expected to increase due to inflation, the overall impact of the decline in the investment marketplace of pension and employee benefit plans, growth initiatives and regulatory filing costs. These earnings estimates do not include any costs related to the Company's acquisition of the electric utility assets of Western Resources which are expected to be approximately $10 to $15 million. The significant capital additions in 2000 are expected to result in increased depreciation and amortization expense in 2001. In addition, because of initiatives undertaken in 2000, it is expected that reduced losses in the non-regulated businesses will contribute to net earnings. This discussion of future expectations is forward looking information within the meaning of Section 21E of the Securities Exchange Act of 1934. The achievement of expected results is dependent upon the assumptions described in the preceding discussion, and is qualified in its entirety by the Private Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding Forward Looking Statements" below) - and the factors described within the disclosure which could cause the Company's actual financial results to differ materially from the expected results enumerated above. LIQUIDITY AND CAPITAL RESOURCES At March 31, 2001, the Company had working capital of $231.9 million including cash and cash equivalents of $161.3 million. This is an increase in working capital of $84.1 million from December 31, 2000. This increase primarily reflects increased cash receipts related to the Company's activity in the wholesale power market. Cash generated from operating activities in the three months ended March 31, 2001 was $109.5 million, an increase of $73.9 million from 2000. This increase was primarily the result of increased profitability and timing of accounts payable payments. In addition, the Company did not make first quarter estimated income tax payments because of an automatic extension granted by the IRS to taxpayers in several counties in New Mexico as a result of wildfires in 2000. This cash increase was partially offset by an increase in the Company's receivables due to higher gas prices and increased wholesale electricity sales. Cash used for investing activities was $47.2 million in 2001 compared to $16.9 million in 2000. This increased spending reflects $14.0 million related to the acquisition of transmission assets and combustion turbine progress payments of $14.5 million. 34 Cash used for financing activities was $8.7 million was primarily used to fund dividend requirements. This compared to $60.1 million used in 2000. This decrease reflects the 2000 repurchase of $34.7 million of senior unsecured notes at a cost of $32.8 million and common stock repurchases in 2000 (see "Stock Repurchase" below). Capital Requirements Total capital requirements include construction expenditures as well as other major capital requirements and cash dividend requirements for both common and preferred stock. The main focus of the Company's construction program is upgrading generation systems, upgrading and expanding the electric and gas transmission and distribution systems and purchasing nuclear fuel. In addition, the Company anticipates significant expenditures to expand its generation capabilities. Projections for total capital requirements and construction expenditures for 2001 are $370 million and $353 million, respectively. Such projections for the years 2001 through 2005 are $1.52 billion and $1.45 billion, respectively. These estimates are under continuing review and subject to on-going adjustment (see "Competitive Strategy" above). The Company's construction expenditures for 2001 were entirely funded through cash generated from operations. The Company currently anticipates that internal cash generation and current debt capacity will be sufficient to meet capital requirements for the years 2001 through 2005. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under its liquidity arrangements. Liquidity At May 1, 2001, the Company had $175 million of available liquidity arrangements, consisting of $150 million from a senior unsecured revolving credit facility ("Credit Facility"), and $25 million in local lines of credit. The Credit Facility will expire in March 2003. There were no outstanding borrowings as of May 1, 2001. The Company's ability to finance its construction program at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, results of operations, credit ratings, regulatory approvals and financial market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term securities, and to obtain short-term credit. In connection with the Company's announcement of its proposed acquisition of Western Resources' electric utility operations, Standard and Poors ("S&P"), Moody's Investor Services ("Moody's") and Fitch IBCA, Duff & Phelps ("Fitch") have placed the Company's securities ratings on negative credit watch pending review of the transaction. The Company is committed to maintaining its investment grade. S&P currently rates the Company's senior unsecured notes ("SUNs") and its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its preferred stock "BB". Moody's rates the Company's SUNs and senior unsecured pollution control revenue bonds "Baa3"; and preferred stock "ba1". The EIP senior secured debt are also rated "Ba1". Fitch rates the Company's SUNs and senior unsecured pollution control revenue bonds "BBB-," the Company's EIP lease obligation "BB+" and the Company's preferred stock "BB-." Investors are 35 cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it may be subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating. Covenants in the Company's Palo Verde Nuclear Generating Station Units 1 and 2 lease agreements limit the Company's ability, without consent of the owner participants in the lease transactions: (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. The Credit Facility imposes similar restrictions regardless of credit ratings. Financing Activities The Company currently has no maturities of long-term financings during the period of 2001 through 2004, not considering the impact of the acquisition of the Western Resources' electric utility operations. However, during this period, the Company could enter into long-term financings for the purpose of strengthening its balance sheet, funding growth and reducing its cost of capital. The Company continues to evaluate its investment and debt retirement options to optimize its financing strategy and earnings potential. No additional first mortgage bonds may be issued under the Company's mortgage. The amount of SUNs that may be issued is not limited by the SUNs indenture. However, debt to capital requirements in certain of the Company's financial instruments would ultimately restrict the Company's ability to issue SUNs. Proposed Holding Company Plan Previously, the Company provided details of its proposed holding company plan as contemplated in response to the implementation dates established under the Restructuring Act before it was amended in February of 2001 (see "Restructuring of the Electric Utility Industry" above). As a result of the amendments to the Restructuring Act delaying customer choice and corporate restructuring for five years, the Company has modified its previously reported holding company plan. Currently, the Company plans to implement a holding company structure as permitted under the amended Restructuring Act. This structure provides for a holding company whose current holdings will be the Company, Avistar and other inactive unregulated subsidiaries. This is expected to be effected through a share exchange between current company shareholders and the proposed holding company, PNM Resources, which is currently a wholly-owned subsidiary of the Company. Avistar and the other inactive unregulated subsidiaries are expected to become wholly-owned subsidiaries of the holding company. There are no current plans to provide the proposed holding company with significant debt financing. The Company's revised holding company plan is subject to regulatory and other approvals. Accordingly, the revised plan may be subject to significant changes before implementation. Stock Repurchase On August 8, 2000, the Company's Board of Directors approved a plan to repurchase up to $35 million of the Company's common stock through the end of the first quarter of 2001. From August 8, 2000 through December 31, 2000 Company repurchased an additional 417,900 shares of its outstanding common stock at a 36 cost of $9.0 million. The Company made no repurchases of its stock during the three months ended March 31, 2001. The Company has no current authorization from its Board of Directors to acquire stock. Dividends The Company's board of directors reviews the Company's dividend policy on a continuing basis. The declaration of common dividends is dependent upon a number of factors including the extent to which cash flows will support dividends, the availability of retained earnings, the financial circumstances and performance of the Company, the PRC's decisions on the Company's various regulatory cases currently pending, the effect of deregulating generation markets and market economic conditions generally. In addition, the ability to recover stranded costs in deregulation (as amended), future growth plans and the related capital requirements and standard business considerations will also affect the Company's ability to pay dividends. Capital Structure The Company's capitalization, including current maturities of long-term debt, at March 31, 2001 and December 31, 2000 is shown below: March 31, December 31, 2001 2000 --------- ---------- Common Equity..................... 51.2 % 47.4 % Preferred Stock................... 0.7 0.7 Long-term Debt.................... 48.1 51.9 --------- ---------- Total Capitalization*.......... 100.0 % 100.0 % ========= ========== * Total capitalization does not include as debt the present value of the Company's lease obligations for PVNGS Units 1 and 2 and EIP, which was $166 million as of March 31, 2001 and $162 million as of December 31, 2000. OTHER ISSUES FACING THE COMPANY RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT Stranded Costs The Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers ("stranded costs"). Stranded costs represent all costs associated with generation-related assets, currently in rates, in excess of the expected competitive market price over the life of those assets and include plant decommissioning costs, regulatory assets, and lease and lease-related costs. Utilities will be allowed to recover no less than 50% of stranded costs through a non-bypassable charge on all customer bills for five years after implementation of customer choice. The PRC could authorize a utility to recover up to 100% of its stranded costs if the PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is necessary to maintain the financial integrity of the public utility; (iii) is necessary to continue adequate and reliable service; and (iv) will not cause an increase in rates to residential or small business customers during the transition period. The Restructuring Act, as 37 amended, also allows for the recovery of nuclear decommissioning costs by means of a separate wires charge over the life of the underlying generation assets (see "NRC Prefunding" below). The calculation of stranded costs is subject to a number of highly sensitive assumptions, including the date of open access, appropriate discount rates and projected market prices, among others. The Restructuring Act, as amended, requires the Company to file a transition plan which includes provisions for the recovery of stranded costs and other expenses associated with the transition to a competitive market no later than January 1, 2005. The Company is unable to predict the amount of stranded costs that it may file to recover at that time. The Company's previous proposal to recover its stranded costs under the original customer choice implementation dates would not accurately represent the Company's expected stranded costs under the amended implementation dates of the Restructuring Act. Approximately $143 million of costs associated with the power supply and energy services businesses under the Restructuring Act were established as regulatory assets. Because of the Company's belief that recovery is probable, these regulatory assets continue to be classified as regulatory assets, although the Company has discontinued Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) and adopted Statement of Financial Accounting Standards No. 101, "Regulated Enterprises--Accounting for the Discontinuance of Application of FASB Statement 71." The amendments to the Restructuring Act allow the Company to recover a portion of its stranded cost assets, related to coal mine decommissioning of $114 million, over the five-year recovery period beginning January 1, 2002. Under the provisions of the law, the Company cannot increase electric utility rates to recover these mine reclamation costs. Accordingly, this provision effectively limits the Company's recovery of certain generation related costs in its current rates. With regard to future rate cases that may occur before restructuring is implemented, these impacted generation costs are recoverable to the extent a future rate case results in rates that include recovery of these costs. The Company believes that the remaining stranded cost assets will be fully recovered in current or future rates. The Company believes that the Restructuring Act, as amended, if properly applied provides an opportunity for recovery of a reasonable amount of stranded costs. If regulatory orders do not provide for a reasonable recovery, the Company is prepared to vigorously pursue judicial remedies. The PRC will make a determination and quantification of stranded cost recovery prior to implementation of restructuring. The determination may have an impact on the recoverability of the related assets and may have a material effect on the future financial results and position of the Company. Transition Cost Recovery In addition, the Restructuring Act, as amended, authorizes utilities to recover in full any prudent and reasonable costs incurred in implementing full open access ("transition costs"). These transition costs are currently scheduled to be recovered through 2012 by means of a separate wires charge. The PRC may extend this date by up to one year. The Company is unable to predict the amount of transition costs it may incur. To date, the Company has capitalized $19.1 million of expenditures that meet the Restructuring Act's definition of transition-related costs. Transition costs for which the Company will seek recovery include professional fees, financing costs, consents relating to the transfer of assets, management information system changes including billing 38 system changes and public and customer education and communications. Recoverable transition costs are currently being capitalized and will be amortized over the recovery period to match related revenues. The Company intends to vigorously pursue remedies available to it should the PRC disallow recovery of reasonable transition costs. Costs not recoverable will be expensed when incurred unless these costs are otherwise permitted to be capitalized under current and future accounting rules. If the amount of non-recoverable transition costs is material, the resulting charge to earnings may have a material effect on the future financial results and position of the Company. NRC Prefunding Pursuant to NRC rules on financial assurance requirements for the decommissioning of nuclear power plants, the Company has a program for funding its share of decommissioning costs for PVNGS through a sinking fund mechanism (see "PVNGS Decommissioning Funding"). The NRC rules on financial assurance became effective on November 23, 1998. The amended rules provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers estimated decommissioning costs through cost of service rates or a "non-bypassable charge". Other mechanisms are prescribed, such as prepayment, surety methods, insurance and other guarantees, to the extent that the requirements for exclusive reliance on the fund mechanism are not met. The Restructuring Act, as amended, allows for the recoverability of 50% up to 100% of stranded costs including nuclear decommissioning costs (see "Stranded Costs"). The Restructuring Act, as amended, specifically identifies nuclear decommissioning costs as eligible for separate recovery over a longer period of time than other stranded costs if the PRC determines a separate recovery mechanism to be in the public interest. In addition, the Restructuring Act, as amended, states that it is not requiring the PRC to issue any order which would result in loss of eligibility to exclusively use external sinking fund methods for decommissioning obligations pursuant to Federal regulations. When final determination of stranded cost recovery is made and if the Company is unable to meet the requirements of the NRC rules permitting the use of an external sinking fund because it is unable to recover all of its estimated decommissioning costs through a non-bypassable charge, the Company may have to pre-fund or find a similarly capital intensive means to meet the NRC rules. There can be no assurance that such an event will not negatively affect the funding of the Company's growth plans. ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS On November 9, 2000, the Company and Western Resources announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. Under the terms of an agreement and plan of restructuring and merger, the Company and Western Resources, whose utility operations consist of its Kansas Power and Light ("KPL") division and Kansas Gas and Electric ("KGE") subsidiary, will both become subsidiaries of a new holding company to be named at a future date. Prior to and as a condition to, the consummation of this combination, Western Resources will reorganize all of its non KPL and KGE assets, including its 85% stake in Protection One and its 45% investment in ONEOK, into Westar Industries which will be spun off to Western Resources' shareholders prior to the acquisition of Western's electric utility assets by the Company. 39 The new holding company will issue 55 million of its shares, subject to adjustment, to Western Resources' shareholders and Westar Industries and 39 million shares to the Company's shareholders. Before any adjustments, the new company will have approximately 94 million shares outstanding, of which approximately 41% will be owned by former Company shareholders and 59% will be owned by former Western Resources shareholders and Westar Industries. In the transaction, each Company share will be exchanged on a one-for-one basis for shares in the new holding company. The portion of each Western Resources share not converted into Westar stock in connection with the spin-off will be exchanged for a fraction of a share of the new holding company in accordance with an exchange ratio to be finalized at closing, depending on the impact of certain adjustments to the transaction consideration. Under the terms of the agreement, Western Resources and Westar Industries have been given an incentive to reduce Western Resources net debt balance prior to the consummation of the transaction. The agreement contains a mechanism to adjust the transaction consideration based on certain activities not affecting the utility operations, which increase the equity of the utility. In addition, Westar Industries has the option of making equity infusions into Western Resources that will be used to reduce the utility's net debt balance prior to closing. Up to $407 million of such equity infusions may be used to purchase additional new holding company common and convertible preferred stock. The effect of such activities would be to increase the number of new holding company shares to be issued to all Western Resources shareholders (including Westar Industries) in the transaction. In February 28, 2001, Westar purchased 14.4 million Western Resources common shares at $24.358 per share (based on a 20 day look-back price at February 28, 2001) at an aggregate price of $350 million. As a result of this equity contribution, the acquisition consideration may be adjusted to include an additional 4.3 million shares of the new holding company depending on the impact of future transactions between Western Resources and Westar. The transaction will be accounted for as a reverse acquisition by the Company as the former Western Resources shareholders will receive the majority of the voting interests in the new holding company. For accounting purposes, Western Resources will be treated as the acquiring entity. Accordingly, all of the assets and liabilities of the Company will be recorded at fair value in the business combination as required by the purchase method of accounting. In addition, the operations of the Company will be reflected in the operations of the combined company only from the date of acquisition. Based on the volume weighted average closing price of the Company's common stock over the two days prior and two days subsequent to the announcement of the transaction of $24.149 per share, the indicated equity consideration of the transaction was approximately $945 million, excluding the potential issuance of additional shares discussed above. There is approximately $2.9 billion of existing Western Resources debt giving the transaction an aggregate enterprise value of approximately $3.8 billion. There are plans for the new holding company to reduce and refinance a portion of the Western Resources debt. At closing, Jeffrey E. Sterba, present chairman, president and chief executive officer of the Company, will become chairman, president and chief executive officer of the new holding company, and David C. Wittig, present chairman, president and chief executive officer of Western Resources, will 40 become chairman, president and chief executive officer of Westar Industries. The Board of Directors of the new company will consist of six current Company board members and three additional directors, two of whom will be selected by the Company from a pool of candidates nominated by Western Resources, and one of whom will be nominated by Westar Industries. The new holding company will be headquartered in New Mexico. Headquarters for the Kansas utilities will remain in Kansas. The Company expects that the shareholders of the new holding company will receive the Company's dividend. The Company's current annual dividend is $0.80 per share. There can be no assurance however that any funds, property or shares will be legally available to pay dividends at any given time or if available, the new holding company's Board of Directors will declare a dividend. On November 27, 2000, Western Resources filed a combined electric rate case requesting a combined $151 million rate increase with the Kansas Corporation Commission (KCC). On April 6, 2001, the KCC filed testimony in the Western rate case recommending a combined rate decrease of $91.7 million. Western Resources has filed rebuttal testimony and hearings are scheduled to be held on the matter. The KCC is required by law to reach a decision by July 28, 2001. The Company has previously stated that based on assumptions at the time it expected its acquisition of Western Resources' electric utility assets to be immediately accretive to earnings. Since that time, the Company's earnings expectations for its stand-alone operations have increased (see "Future Expectations") significantly while Western Resources reported earnings have declined for the year ended December 31, 2000 as compared to the year ended December 31, 1999. In addition, Western Resources' earnings outlook may also be influenced by the outcome of its electric utility rate case now before the KCC (see above). Calculations regarding accretion/dilution are subject to many key assumptions with a high degree of volatility, including assumptions regarding future earnings for both companies, which in turn are subject to assumptions regarding rate case decisions, terms and conditions of regulatory approvals for the transactions and market conditions. Based on updated information regarding the Company's earnings outlook and Western Resources historic results, the Company's previous forecast of the combined company would now show earnings dilution. Whether or not the combination would be dilutive or accretive is highly dependent on future events that cannot be predicted at this time, including the results of the pending Western Resources rate case and terms and conditions that might be imposed as a result of the applications for regulatory approvals. On May 8, 2001, the KCC commenced an investigation of the proposed split-off of Westar Industries from Western Resources and whether the transaction will adversely affect the ability of Western Resources' electric utility operations to provide efficient and sufficient electric utility service at just and reasonable rates to its customers in the state of Kansas. The successful split-off of Westar is a condition of the proposed acquisition of Western Resources' electric utility assets. The companies expect the transaction to be completed within the next 12 to 15 months. The successful spin-off of Westar Industries from Western Resources is required prior to the consummation of the transaction. The transaction is also conditioned upon, among other things, approvals from both companies' shareholders and customary regulatory approvals from the Kansas Corporation 41 Commission, the New Mexico Public Regulation Commission, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Federal Communications Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse regulatory outcome related to other actions involving rate making or approval of regulatory plans may affect the consummation of the transaction. The new holding company expects to register as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. The Company expects that all of the above mentioned approvals will be obtained; however, such approvals are not assured. WESTERN UNITED STATES WHOLESALE POWER MARKET A significant portion of the Company's earnings in 2001 was derived from the Company's wholesale power trading operations which benefited from the strong demand and high wholesale prices in the Western United States. These market conditions were primarily driven by the electric power supply shortages in the Western United States. As a result of the supply imbalance, the wholesale power market in the Western United States has become extremely volatile and, while providing many marketing opportunities, presents significant risk to companies selling power into this marketplace. The power market in the Western United States has been the subject of widespread national attention and continues to evolve on nearly a daily basis. At the heart of the situation are flaws in the California deregulation legislation and a significant imbalance between electric supply and demand. These circumstances have been aggravated by other factors such as increases in gas supply costs, weather conditions and transmission constraints. Congress and the California legislature are considering various legislation that would provide long or short-term relief, including potentially price caps on the wholesale price of electricity that could be charged, relaxation of certain environmental standards, and windfall profit taxes on sellers into the California wholesale market. The FERC and the California Public Utilities Commission ("CPUC") have also entered a series of orders addressing, respectively, the wholesale pricing of electricity into the California market and the retail pricing of electricity to California consumers. These initiatives, individually or collectively, could place significant downward pressure on wholesale prices. The Company cannot predict the ultimate outcome of these governmental initiatives and their effect on the Western United States power market or on the Company's ability to market into the California market. During 2001, regional wholesale electricity prices have reached over $1,000 per MWh mainly due to the electric power shortages in the West. Two of California's major utilities, SCE and PG&E, have been unable to fully recover their wholesale power costs from their ratepayers. As a result, both utilities experienced severe liquidity constraints that caused PG&E to seek bankruptcy protection while SCE has been forced to consider bankruptcy. In response to the turmoil in the California energy market, the FERC initially imposed a "soft" price cap of $150 per MWh for sales to the California Power Exchange ("Cal PX") and the California Independent System Operator ("Cal ISO") that required any wholesale sales of electricity into the these markets be capped at $150 MWh unless the seller could demonstrate that its costs exceed the cap. This price cap was effectively modified by three FERC orders issued in March and April 2001 that directed certain power suppliers to provide refunds in excess of $100 million for overcharges calculated on the basis of a formula that sanctioned wholesale prices considerably in excess of the $150/MWh level. On April 26, 2001, the FERC adopted an order establishing prospective mitigation and a monitoring plan for the California wholesale markets and which established a further investigation of public utility rates in wholesale Western energy 42 markets. The plan reflected in the April 26 order replaced the $150/MWh soft cap previously established and would apply during periods of system emergency. The Company is presently evaluating the effects, if any, of the April 26 order on its wholesale marketing efforts into the California markets. In addition, in April 2001, SCE and the Governor of California announced an agreement in which the state would purchase SCE's 12,000 mile transmission system for $2.8 billion. In exchange, SCE agreed to sell power from its plants under cost-based, rather than market-based pricing for the next 10 years. The agreement still requires federal regulatory and California legislative approvals. It is unclear what effect these measures will have on the price of electricity in California and the surrounding states. Such measures may have an impact on the sustainability of the high electric power prices experienced in the first quarter of 2001. In 2001, approximately $2 million in wholesale power sales by the Company were made directly to the Cal PX, which was the main market for the purchase and sale of electricity in the state in the beginning of 2001 or the Cal ISO which manages the state's electricity transmission network. In January and February 2001, SCE and PG&E, major purchasers of power from the California PX and ISO, defaulted on payments due the Cal PX for power purchased from the PX in 2000. These defaults caused the Cal PX to seek bankruptcy protection. The Company will be filing proofs of claims in the bankruptcy proceeding. At March 31, 2001, amounts due from the Cal PX or Cal ISO for power sold to them totaled $8.1 million. Prior to its bankruptcy filing, the Cal PX undertook to charge back these defaults of SCE and PG&E to other market participants, in proportion to their participation in the markets. The Company was invoiced for $2.3 million as its proportionate share under the Cal PX tariff. The Company, as well as a number of power marketers and generators, filed complaints with the FERC to halt the Cal PX's attempt to collect these payments under the charge-back mechanism, claiming the mechanism was not intended for these purposes, and even if it was so intended, such an application was unreasonable and destabilizing to the California power market. The FERC has issued a ruling on these complaints eliminating the "charge-back" mechanism. With the demise of the Cal PX in February 2001, the California Department of Water Resources ("Cal DWR") commenced a program of purchasing electric power needed to supply California utility customers serviced by PG&E and SCE as these utilities lacked the liquidity to purchase supplies. The purchases are currently financed by legislative appropriation, but this funding is expected to be replaced with the issuance of revenue bonds by the state under recent legislation signed by the California governor. These bonds are expected to be repaid by the utility ratepayers. In the first quarter of 2001, the Company began to sell power to the Cal DWR. The Company regularly monitors its credit risk with regard to its Cal DWR sales and believes its exposure is prudent. In addition to sales directly to California, the Company sells power to customers in other jurisdictions who sell to California and whose ability to pay the Company may be dependent on payment from California. The Company is unable to determine whether its non-California power sales ultimately are resold in the California market. The Company's credit risk is monitored by its Risk Management Committee, which is comprised of senior finance and operations managers. The Company seeks to minimize its exposure through established credit limits, a diversified customer base and the structuring of transactions to take advantage of off-setting positions with its customers. To the extent these customers who sell power into California are dependent on payment from California to make their payments to the Company, the Company may be exposed to credit risk which did not exist prior to the California situation. 43 In the first quarter of 2001, in response to the increased credit risk and market price volatility described above, the Company provided an additional allowance against revenue of $13.2 million for anticipated losses to reflect management's estimate of the increased risk in the wholesale power market and its impact on 2001 revenues. This determination was based on a methodology that considers the credit ratings of its customers and the price volatility in the marketplace, among other things. Based on information available at March 31, 2001, the Company believes the total allowance for anticipated losses, currently established at $21.7 million, is adequate for management's estimate of potential uncollectible accounts. The Company will continue to monitor the wholesale power marketplace and adjust its estimates accordingly. The CPUC has commenced an investigation into the functioning of the California wholesale power market and its associated impact on retail rates. The Company, along with other power suppliers in California, has been served with a subpoena in connection with this investigation and has responded to the subpoena. The Company has been advised that the California Attorney General is conducting an investigation into possibly unlawful, unfair or anti-competitive behavior affecting electricity rates in California, and that Company documents will be subpoenaed in the future in connection with this investigation. Other related investigations have been commenced by other federal and state governmental bodies. In addition, there are several class action lawsuits that have been filed in California against generators and wholesale sellers of energy into the California market. These actions allege, in essence, that the defendants engaged in unlawful and unfair business practices to manipulate the wholesale energy market, fix prices and restrain supply, and thereby drive up prices. The Company is not a named defendant in any of these actions. The Company does not believe that these matters will have a material adverse effect on its results of operations or financial position. As noted above, SCE has publicly stated that it may be forced to declare bankruptcy. SCE is a 15.8% participant in PVNGS and a 48.0% participant in Four Corners. Pursuant to an agreement among the participants in PVNGS and an agreement among the participants in Four Corners Units 4 and 5, each participant is required to fund its proportionate share of operation and maintenance, capital, and fuel costs of PVNGS and Four Corners Units 4 and 5. The Company estimates SCE's total monthly share of these costs to be approximately $7.1 million for PVNGS and $8.0 million for Four Corners. The agreements provide that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant for a period of six months. During this time the defaulting participant is entitled to its share of the power generated by the respective station. After this grace period, the defaulting participant must make its payments in arrears before it is entitled to its continuing share of power. As of May 1, 2001, SCE has not defaulted on its payment obligations with respect to PVNGS and Four Corners. The Company is unable to predict whether the California situation will cause SCE to default on its payment obligations. 44 Implementation of New Customer Billing System On November 30, 1998, the Company implemented a new customer billing system. Due to a significant number of problems associated with the implementation of the new billing system, the Company was unable to generate appropriate bills for all its customers through the first quarter of 1999 and was unable to analyze delinquent accounts until November 1999. As a result of the delay of normal collection activities, the Company incurred a significant increase in delinquent accounts, many of which occurred with customers that no longer have active accounts with the Company. As a result, the Company significantly increased its estimated bad debt costs throughout 1999 and 2000. The Company continued its analysis and collection efforts of its delinquent accounts resulting from the problems associated with the implementation of the new customer billing system throughout 2000 and identified additional bad debt exposure. By the end of 2000, the Company completed its analysis of its delinquent accounts and resumed its normal collection procedures. As a result, the Company determined that $13.5 million of customer receivables would not be collectible. Based upon information available at March 31, 2001, the Company believes the allowance for doubtful accounts of $11.0 million is adequate for management's estimate of potential uncollectible accounts. In addition, due to the significantly higher natural gas prices experienced in November and December 2000, the Company increased its bad debt expense by approximately $1 million for the three months ended March 31, 2001 and $2 million for the year ended December 31, 2000 in anticipation of higher than normal delinquency rates. The Company expects this trend to continue as long as natural gas prices remain higher than historical levels. The following is a summary of the allowance for doubtful accounts during the three months ended March 31, 2001 and the year ended December 31, 2000:
March 31, December 31, 2001 2000 ------------- ------------ Allowance for doubtful accounts, beginning of year.................................................... $ 8,963 $12,504 Bad debt expense............................................. 3,434 9,980 Less: Write off (adjustments) of uncollectible accounts..... 1,399 13,521 ------------ ------------ Allowance for doubtful accounts, end of year ................ $10,998 $ 8,963 ============ ============
Effects of Certain Events on Future Revenues The Company's 100 MW power sale contract with San Diego Gas and Electric Company ("SDG&E") expired on April 30, 2001 following FERC's acceptance for filing of a cancellation notice filed by the Company. The Company expects to replace these revenues, based on current market conditions. In addition, previously reported litigation between the Company and SDG&E regarding prior years' contract pricing has been resolved in the Company's favor. On October 4, 1999, Western Area Power Administration ("WAPA") filed a petition at the FERC requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA under the Company's Open Access Transmission Tariff on behalf of the United States Department of Energy 45 ("DOE") as contracting agent for Kirtland Air Force Base ("KAFB"). On April 13, 2001, the FERC entered an order favorable to the Company, denying the WAPA transmission application. The order is not yet final. In a related PRC proceeding, the parties are pursuing informal settlement discussions and awaiting a PRC order on the scope of the case (See Item 3. - "Legal Proceedings - Other Proceedings - KAFB Contract"). COAL FUEL SUPPLY In 1996, the Company was notified by SJCC that the Navajo Nation proposed to select certain properties within the San Juan and La Plata Mines (the "mining properties") pursuant to the Navajo-Hopi Land Settlement Act of 1974 (the "Act"). The mining properties are operated by SJCC under leases from the BLM and comprise a portion of the fuel supply for the SJGS. An administrative appeal by SJCC is pending. In the appeal, SJCC argued that transfer of the mining properties to the Navajo Nation may subject the mining operations to taxation and additional regulation by the Navajo Nation, both of which could increase the price of coal that might potentially be passed on to the SJGS through the existing coal sales agreement. The Company is monitoring the appeal and other developments on this issue and will continue to assess potential impacts to the SJGS and the Company's operations. The Company is unable to predict the ultimate outcome of this matter. FUEL, WATER AND GAS NECESSARY FOR GENERATION OF ELECTRICITY The Company's generation mix for 2001 was 68.25% coal, 28.40% nuclear and 3.35% gas and oil. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits and the generally abundant supply of nuclear fuel, the Company believes that adequate sources of fuel are available for its generating stations. Water for Four Corners and SJGS is obtained from the San Juan River. BHP holds rights to San Juan River water and has committed a portion of those rights to Four Corners through the life of the project. The Company and Tucson have a contract with the USBR for consumption of 16,200 acre feet of water per year for the SJGS. The contract expires in 2005. In addition, the Company was granted the authority to consume 8,000 acre feet of water per year under a state permit that is held by BHP. The Company is of the opinion that sufficient water is under contract for the SJGS through 2005. The Company has signed a contract with the Jicarilla Apache Tribe for a twenty-two year term, beginning in 2006, for replacement of the current USBR contract for 16,200 acre feet of water. The contract must still be approved by the USBR and is also subject to environmental approvals. The Company is actively involved in the San Juan River Recovery Implementation Program to mitigate any concerns with the taking of the negotiated water supply from a river that contains endangered species and critical habitat. The Company believes that it will continue to have adequate sources of water available for its generating stations. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. These contracts are generally sufficient to meet the Company's peak-day demand. The Company serves certain cities which depend on EPNG or Transwestern Pipeline Company for transportation of gas supplies. Because these cities are not directly connected to the Company's transmission facilities, gas transported by these companies is the sole supply source for those cities. The Company believes that adequate sources of gas are available for its distribution systems. 46 NEW SOURCE REVIEW RULES The United States Environmental Protection Agency ("EPA") has proposed changes to its New Source Review ("NSR") rules that could result in many actions at power plants that have previously been considered routine repair and maintenance activities (and hence not subject to the application of NSR requirements) as now being subject to NSR. In November 1999, the Department of Justice at the request of the EPA filed complaints against seven companies alleging the companies over the past 25 years had made modifications to their plants in violation of the NSR requirements, and in some cases the New Source Performance Standards ("NSPS") regulations. Whether or not the EPA will prevail is unclear at this time. The EPA has reached a settlement with one of the companies sued by the Justice Department and is in the process of attempting to negotiate settlement agreements with one of those other companies. No complaint has been filed against the Company, and the Company believes that all of the routine maintenance, repair, and replacement work undertaken at its power plants was and continues to be in accordance with the requirements of NSR and NSPS. However, by letter dated October 23, 2000, the New Mexico Environment Department ("NMED") made an information request of the Company, advising the Company that the NMED was in the process of assisting the EPA in the EPA's nationwide effort "of verifying that changes made at the country's utilities have not inadvertently triggered a modification under the Clean Air Act's Prevention of Significant Determination ("PSD") policies." The Company has responded to the NMED information request. The nature and cost of the impacts of EPA's changed interpretation of the application of the NSR and NSPS, together with proposed changes to these regulations, may be significant to the power production industry. However, the Company cannot quantify these impacts with regard to its power plants. It is also unknown what changes in EPA policy, if any, may occur in the NSR area as a result of the change in administration in Washington. If the EPA should prevail with its current interpretation of the NSR and NSPS rules, the Company may be required to make significant capital expenditures which could have a material adverse effect on the Company's financial position and results of operations. COMPLIANCE WITH ENVIRONMENTAL LAWS AND REGULATIONS The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes. The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially 47 responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). The Company's recorded estimated minimum liability to remediate its identified sites is $6.8 million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $11.6 million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company. In 2001, the Company anticipates spending $1.4 million for remediation and $0.7 million for control and prevention. The majority of the March 31, 2001 environmental liability is expected to be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company. NATURAL GAS EXPLOSION On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. At least one passerby received minor injuries from the blast. Several claims for property and business interruption damages have been received by the Company. The cause of the leak is unknown and the Company is conducting an investigation into the explosion. No lawsuits against the Company have yet been served on the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur. There can be no assurance that the outcome of this matter will not have a material impact on the results of operations and financial position of the Company. NAVAJO NATION TAX ISSUES APS, the operating agent for Four Corners, has informed the Company that in March 1999, APS initiated discussions with the Navajo Nation regarding various tax issues in conjunction with the expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to the possessory interest tax and the business activity tax associated with the Four Corners operations on the reservation. The Company believes that the resolution of these tax issues will require an extended process and could potentially affect the cost of conducting business activities on the reservation. The Company is unable to predict the ultimate outcome of discussions with the Navajo Nation regarding these tax issues. 48 NEW AND PROPOSED ACCOUNTING STANDARDS Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"): The Company implemented SFAS 133, as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133, as amended, also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. Because the Company's derivative instruments as defined by SFAS 133, as amended, are currently marked-to-market or are classified as cash flow hedges, the adoption of SFAS 133, as amended, did not have an impact on the net earnings of the Company. However, the adoption of SFAS 133, as amended, did increase comprehensive income by $6.1 million, net of taxes for the recording of the Company's cash flow hedges. The physical contracts will subsequently be recognized as a component of the cost of purchased power when the actual physical delivery occurs. At January 1, 2001, the derivative instruments designated as cash flow hedges had a gross asset position of $9.9 million on the hedged transactions. See Note 4 for financial instruments currently marked-to-market. It is a common practice within the electric utility industry to net offsetting purchase and sales contracts between two or more counterparties to facilitate transmission. This is commonly referred to as a "book-out." Whether a book-out occurs is dependant on a number of factors, including agreement by all parties in the chain of the transaction, efficiency of the transaction flow, congestion on the electrical transmission system, and system reliability issues. Book-outs do not occur until a short time before the electricity is due to be physically delivered, no matter when the original contracts in the chain were entered into, and have no legal standing should one of the parties in the chain default. The Derivatives Implementation Group ("DIG") of the FASB has reached a tentative conclusion that all contracts for the sale or purchase of electricity that are subject to being booked out, whether that is the intent of the counterparties or not, do not qualify for the normal sale or normal purchase exception. The conclusion is tentative until formally cleared by the FASB and incorporated in an FASB staff implementation guide. If the conclusion of the DIG is accepted by the FASB, the Company may be required to mark-to-market its transactions that it has classified as normal purchases and normal sales. The Company is unable to determine the impact of this conclusion. 49 Decommissioning: The Staff of the Securities and Exchange Commission ("SEC") has questioned certain of the current accounting practices of the electric industry regarding the recognition, measurement and classification of decommissioning costs for nuclear generating stations in financial statements of electric utilities. In February 2000, the Financial Accounting Standards Board ("FASB") issued an exposure draft regarding Accounting for Obligations Associated with the Retirement of Long-Lived Assets ("Exposure Draft"). The Exposure Draft requires the recognition of a liability for an asset retirement obligation at fair value. In addition, present value techniques used to calculate the liability must use a credit adjusted risk-free rate. Subsequent remeasures of the liability would be recognized using an allocation approach. The Company has not yet determined the impact of the Exposure Draft. DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS Statements made in this filing that relate to future events are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of the Company are based upon current expectations and are subject to risk and uncertainties, as are the forward-looking statements with respect to the benefits of the Company's proposed acquisition of Western Resources and the businesses of the Company and Western Resources. The Company assumes no obligation to update this information. Because actual results may differ materially from expectations, the Company cautions readers not to place undue reliance on these statements. A number of factors, including weather, fuel costs, changes in supply and demand in the market for electric power, the performance of generating units and transmission system, and state and federal regulatory and legislative decisions and actions, including rulings issued by the New Mexico Public Regulation Commission pursuant to the Electric Utility Industry Restructuring Act of 1999, as amended, and in other cases now pending or which may be brought before the PRC and any action by the New Mexico Legislature to further amend or repeal that Act, or other actions relating to restructuring or stranded cost recovery, or federal or state regulatory, legislative or legal action connected with the California wholesale power market, could cause the Company's results or outcomes to differ materially from those indicated by such forward-looking statements in this filing. In addition, factors that could cause actual results or outcomes related to the proposed acquisition of Western Resources to differ materially from those indicated by such forward looking statements include, but are not limited to, risks and uncertainties relating to: the possibility that shareholders of the Company and/or Western Resources will not approve the transaction, the risks that the businesses will not be integrated successfully, the risk that the benefits of the transaction may not be fully realized or may take longer to realize than expected, disruption from the transaction making it more difficult to maintain relationships with clients, employees, suppliers or other third parties, conditions in the financial markets relevant to the proposed transaction, the receipt of regulatory and other approvals of the transaction, that future circumstances could cause business decisions or accounting treatment to be decided differently than now intended, changes in laws or regulations, changing governmental policies and regulatory actions with respect to allowed revenue requirements, rates of return on equity and equity ratio limits, industry and rate structure, stranded cost recovery, operation of nuclear power facilities, acquisition, disposal, depreciation and amortization 50 of assets and facilities, operation and construction of plant facilities, recovery of fuel and purchased power costs, decommissioning costs, present or prospective wholesale and retail competition (including retail wheeling and transmission costs), political and economic risks, changes in and compliance with environmental and safety laws and policies, weather conditions (including natural disasters such as tornadoes), population growth rates and demographic patterns, competition for retail and wholesale customers, availability, pricing and transportation of fuel and other energy commodities, market demand for energy from plants or facilities, changes in tax rates or policies or in rates of inflation or in accounting standards, unanticipated delays or changes in costs for capital projects, unanticipated changes in operating expenses and capital expenditures, capital market conditions, competition for new energy development opportunities and legal and administrative proceedings (whether civil, such as environmental, or criminal) and settlements, and the impact of Protection One's financial condition on Western Resources' consolidated results. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices and also adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. Information about market risk is set forth in Note 4 to the Notes to the Consolidated Financial Statements and incorporated by reference. The following additional information is provided. The Company uses value at risk ("VAR") to quantify the potential exposure to market movement on its open contracts and excess generating assets. The VAR is calculated utilizing the variance/co-variance methodology over a three day period within a 99% confidence level. The Company's VAR as of March 31, 2001 from its electric trading contracts was $31.8 million. The Company's wholesale power marketing operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. The Company's VAR calculation considers this exposure. The Company's VAR is regularly monitored by the Company's Risk Management Committee which is comprised of senior finance and operations managers. The Risk Management Committee has put in place procedures to ensure that increases in VAR are reviewed and, if deemed necessary, acted upon to reduce exposures. In addition, the Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to access and monitor the financial conditions of counterparties. Credit exposure is also regularly monitored by the Company's Risk Management committee. The VAR represents an estimate of the potential gains or losses that could be recognized on the Company's wholesale power marketing portfolio given current volatility in the market, and is not necessarily indicative of actual 51 results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market rates, operating exposures, and the timing thereof, as well as changes to the Company's wholesale power marketing portfolio during the year. The Company's outstanding long-term debt is fixed rate debt and not subject to interest rate fluctuation. The Company has not historically utilized interest rate swaps or similar hedging arrangements to protect against fluctuations in interest rates. PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The following represents a discussion of legal proceedings that first became a reportable event in the current year or material developments for those legal proceedings previously reported in the Company's 2000 Annual Report on Form 10-K ("Form 10-K"). This discussion should be read in conjunction with Item 3. - Legal Proceedings in the Company's Form 10-K. PVNGS Water Supply Litigation As previously reported, The Company understands that a summons served on APS in 1986 required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons and the rights of the PVNGS participants, including the Company, to the use of groundwater and effluent at PVNGS are potentially at issue in this action. APS, as the PVNGS project manager, filed claims that dispute the court's jurisdiction over the PVNGS participants' groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. APS and other parties have petitioned the United States Supreme Court for review of this decision and the petition was denied. In addition, the Arizona Supreme Court issued a decision affirming the lower court's criteria for solving groundwater claims. APS and other parties filed motions for reconsideration on one aspect of that decision. Those motions have been denied by the Arizona Supreme Court. APS and other parties have petitioned the United States Supreme Court for review of the Arizona Supreme Court's decision affirming the lower court's criteria for resolving groundwater claims. The Company is unable to predict the outcome of this case. Purported Navajo Environmental Regulation As previously reported, in July 1995 the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the "Acts"). Pursuant to the Acts, the Navajo Nation Environmental Protection Agency is authorized to promulgate regulations covering air quality, drinking water and 52 pesticide activities, including those that occur at Four Corners. In February 1998, the EPA issued regulations specifying provisions of the Clean Air Act for which it is appropriate to treat Indian tribes in the same manner as states. The EPA indicated that it believes that the Clean Air Act generally would supersede pre-existing binding agreements that may limit the scope of tribal authority over reservations. In February 1999, the EPA issued regulations under which Federal operating permits for stationary sources in Indian Country can be issued pursuant to Title V of the Clean Air Act. The regulations rely on authority contained in an earlier rule in which the EPA outlined treatment of tribes as states under the Clean Air Act. The Company as a participant in the Four Corners Power Plant ("Four Corners") and as operating agent and joint owner of San Juan Generating Station, and owners of other facilities located on other reservations located in New Mexico, has filed appeals to contest the EPA's authority under the regulations. On July 14, 2000, the DC Circuit issued its opinion denying the Company's motion for rehearing of the decision denying claims concerning the interpretation by EPA of tribal authority under the Clean Air Act. The Company filed a petition for writ of certiorari to the United States Supreme Court, which was denied on April 16, 2001. The Company does not expect any immediate impacts as a result of this decision but will continue to monitor developments with the Navajo Nation and EPA. The Company cannot predict the outcome of these proceedings or any subsequent determinations by the EPA. There can be no assurance that the outcome of these matters will not have a material impact on the results of operations and financial position of the Company. KAFB Contract The Company reported previously that the DOE had entered into an agency agreement with WAPA on behalf of KAFB, one of the Company's largest retail electric customers, by which WAPA would competitively procure power for KAFB. The proposed wholesale power procurement was to begin at the expiration of KAFB's power service contract with the Company in December 1999. On May 4, 1999, the Company received a request for network transmission service from WAPA pursuant to Section 211 of the Federal Power Act to facilitate the delivery of wholesale power to KAFB over the Company's transmission system. The Company denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB is and will continue to be a retail customer until the effective date KAFB can elect customer choice service under the provisions of the Restructuring Act of 1999. The Company also cited several provisions of Federal law that prohibit the provision of such service to WAPA. On September 30, 1999, WAPA filed a petition at the FERC requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA under the Company's Open Access Transmission Tariff on behalf of DOE and several other entities located on KAFB. The petition claimed KAFB is a wholesale customer of the Company, not a retail customer. By order entered on April 13, 2001 the FERC denied the WAPA transmission application. The FERC order determined, among other things, that WAPA had failed to demonstrate that its sales to DOE are sales for resale and also that WAPA failed to qualify for certain claimed exemptions under the Federal Power Act that would have entitled it to provide expanded service to DOE. The period for the potential filing of a request for rehearing has not yet expired, but to date WAPA has not sought rehearing at the FERC. In a separate but related proceeding, the Company and the United States Executive Agencies on behalf of KAFB are involved in a PRC case regarding a dispute over the specific Company tariff language under which the Company provides retail service to KAFB. The Company agreed to continue to provide service to KAFB after expiration of the contract, pending resolution of all relevant issues. The parties are presently pursuing informal settlement discussions with regard to this case. The Company intends to vigorously defend its position at the PRC. 53 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits: 3.2 By-laws of Public Service Company of New Mexico With All Amendments to and including April 7, 2001 15.0 Letter Re: Unaudited Interim Financial Information b. Reports on Form 8-K: Report dated and filed February 26, 2001 reporting the Company's Comparative Operating Statistics for the month of January 2001 and 2000 and the year ended January 31, 2001 and 2000. Report dated and filed February 28, 2001 reporting the Company declares Preferred Dividends. Report dated and filed March 1, 2001 reporting the Company's year-end earnings results and press conference transcript. Report dated and filed March 20, 2001 reporting the Company's Comparative Operating Statistics for the month of February 2001 and 2000 and the year ended February 28, 2001 and 2000. Report dated and filed March 27, 2001 reporting the Company raises earnings forecast for the first quarter. Report dated and filed April 11, 2001 reporting the Company's Board amends Articles and Bylaws to reflect changes in State law, renames the planned holding company as "PNM Resources, Inc." Report dated and filed April 11, 2001 reporting the Company's "Transforming Ideas Into Results" 2000 Annual Report to shareholders. Report dated and filed April 12, 2001 reporting the Company's Comparative Operating Statistics for the month of March 2001 and 2000 and the year ended March 31, 2001 and 2000. Report dated and filed April 16, 2001 reporting the Company hosts first quarter 2001 earnings conference call. Report dated and filed April 18, 2001 reporting the Company declares common and preferred stock dividends. Report dated and filed April 18, 2001 reporting the Company's quarter ended March 31, 2001 Earnings Announcement and Consolidated Statement of Earnings. Report dated and filed May 2, 2001 reporting the Company's sustainable growth underlies record earnings. 54 b. Reports on Form 8-K: (Continued) Report dated and filed May 2, 2001 reporting the Company's slide presentation "Transforming Ideas Into Results" delivered by the Company's Chairman, President and Chief Executive Officer, Jeff Sterba. 55 Signature Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW MEXICO --------------------------------------------- (Registrant) Date: May 15, 2001 /s/ John R. Loyack --------------------------------------------- John R. Loyack Vice President, Corporate Controller and Chief Accounting Officer (Officer duly authorized to sign this report) 56