-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, C5fdH88iaRUyfU7+7JppkI6iPI91LC9j2rtClC/R3sNmu6tVMbj5V+//EA9Nlg5l uZX3iytZAO24oWGi7tMrgw== 0001108426-02-000026.txt : 20020515 0001108426-02-000026.hdr.sgml : 20020515 20020515171415 ACCESSION NUMBER: 0001108426-02-000026 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 20020331 FILED AS OF DATE: 20020515 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PNM RESOURCES CENTRAL INDEX KEY: 0001108426 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 850468296 STATE OF INCORPORATION: NM FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 333-32170 FILM NUMBER: 02653718 BUSINESS ADDRESS: STREET 1: ALVARADO SQUARE STREET 2: NEW MEXICO CITY: ALBUQUERQUE STATE: NM ZIP: 87158 BUSINESS PHONE: 5052412700 MAIL ADDRESS: STREET 1: ALVARADO SQUARE CITY: ALBUQUERQUE STATE: NM ZIP: 87158 FORMER COMPANY: FORMER CONFORMED NAME: MANZANO CORP DATE OF NAME CHANGE: 20000303 10-Q 1 f10q_05152002.txt FIRST QUARTER 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, 2002 -------------- - OR - [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _________________ Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification No. - ----------- ----------------------------------- ------------------ 333-32170 PNM Resources, Inc. 85-0468296 (A New Mexico Corporation) Alvarado Square Albuquerque, New Mexico 87158 (505) 241-2700 1-6986 Public Service Company of New Mexico 85-0019030 (A New Mexico Corporation) Alvarado Square Albuquerque, New Mexico 87158 (505) 241-2700 Securities Registered Pursuant To Section 12(b) Of The Act: Name of Each Exchange Registrant Title of Each Class on Which Registered - ---------- ------------------- --------------------- PNM Resources, Inc. Common Stock, No Par Value New York Stock Exchange 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. Registrant Class Outstanding at May 1, 2002 - ---------- ----- -------------------------- PNM Resources, Inc. Common Stock, No Par Value 39,117,799 PNM RESOURCES, INC. AND SUBSIDIARIES INDEX Page No. PART I. FINANCIAL INFORMATION: Report of Independent Public Accountants............................. 3 ITEM 1. FINANCIAL STATEMENTS PNM Resources, Inc. Consolidated Statements of Earnings Three Months Ended March 31, 2002 and 2001................ 4 Consolidated Balance Sheets Three Months Ended March 31, 2002 and December 31, 2001... 5 Consolidated Statements of Cash Flows Three Months Ended March 31, 2002 and 2001................ 7 Consolidated Statements of Comprehensive Income Three Months Ended March 31, 2002 and 2001................ 8 Public Service Company of New Mexico Consolidated Statements of Earnings Three Months Ended March 31, 2002 and 2001................ 9 Consolidated Balance Sheets Three Months Ended March 31, 2002 and December 31, 2001... 10 Consolidated Statements of Cash Flows Three Months Ended March 31, 2002 and 2001................ 12 Consolidated Statements of Comprehensive Income Three Months Ended March 31, 2002 and 2001................ 13 Notes to Consolidated Financial Statements........................ 14 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............ 27 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.............................................. 57 PART II. OTHER INFORMATION: ITEM 1. LEGAL PROCEEDINGS........................................... 60 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................ 65 Signature ......................................................... 66 2 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of PNM Resources, Inc. and Public Service Company of New Mexico: We have reviewed the accompanying consolidated balance sheets and statements of capitalization of PNM Resources, Inc. and Subsidiaries and the consolidated balance sheets and statements of capitalization of Public Service Company of New Mexico and Subsidiaries as of March 31, 2002, and the related consolidated statements of earnings, cash flows and comprehensive income for the three-month periods then ended. 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 sheets and statements of capitalization of PNM Resources, Inc. and Subsidiaries and Public Service Company of New Mexico and Subsidiaries as of December 31, 2001, and the related consolidated statements of earnings, cash flows and comprehensive income for the year then ended (not presented herein), and in our report dated February 1, 2002, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheets as of December 31, 2001 is fairly stated, in all material respects, in relation to the consolidated balance sheets from which it has been derived. ARTHUR ANDERSEN LLP Albuquerque, New Mexico May 15, 2002 3 ITEM 1. FINANCIAL STATEMENTS PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited) Three Months Ended March 31, ---------------------------- 2002 2001 ------------- ------------ (In thousands, except per share amounts) Operating Revenues: Electric...................................... $ 203,963 $544,594 Gas........................................... 109,201 191,936 Unregulated businesses........................ 832 - ------------- ------------ Total operating revenues.................... 313,996 736,530 ------------- ------------ Operating Expenses: Cost of energy sold........................... 155,108 497,098 Administrative and general.................... 32,064 39,488 Energy production costs....................... 34,971 35,025 Depreciation and amortization................. 24,779 24,219 Transmission and distribution costs........... 16,537 15,277 Taxes, other than income taxes................ 8,484 7,217 Income taxes.................................. 9,366 40,906 ------------- ------------ Total operating expenses.................... 281,309 659,230 ------------- ------------ Operating income............................ 32,687 77,300 ------------- ------------ Other Income and Deductions Other......................................... 12,230 4,560 Income tax expense............................ (4,842) (1,926) ------------- ------------ Net other income and deductions............. 7,388 2,634 ------------- ------------ Income before interest charges.............. 40,075 79,934 ------------- ------------ Interest charges................................ 15,126 16,382 ------------- ------------ Net Earnings.................................... 24,949 63,552 Preferred Stock Dividend Requirements........... 146 146 ------------- ------------ Net Earnings Applicable to Common Stock......... $ 24,803 $ 63,406 ============= ============ Net Earnings per Common Share: Basic......................................... $ 0.63 $ 1.62 ============= ============ Diluted....................................... $ 0.63 $ 1.60 ============= ============ Dividends Paid per Common Share................. $ 0.20 $ 0.20 ============= ============ The accompanying notes are an integral part of these financial statements. 4 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
March 31, December 31, 2002 2001 --------------- -------------- (Unaudited) (In thousands) ASSETS Utility Plant: Electric plant in service..................................... $2,109,993 $2,118,417 Gas plant in service.......................................... 589,097 575,350 Common plant in service and plant held for future use......... 49,546 45,223 --------------- -------------- 2,748,636 2,738,990 Less accumulated depreciation and amortization................ 1,254,787 1,234,629 --------------- -------------- 1,493,849 1,504,361 Construction work in progress................................. 301,646 249,656 Nuclear fuel, net of accumulated amortization of $19,533 and $16,954....................................... 25,817 26,940 --------------- -------------- Net utility plant........................................... 1,821,312 1,780,957 --------------- -------------- Other Property and Investments: Other investments............................................. 440,082 552,453 Non-utility property, net of accumulated depreciation of $1,623 and $1,580......................................... 1,742 1,784 --------------- -------------- Total other property and investments........................ 441,824 554,237 --------------- -------------- Current Assets: Cash and cash equivalents..................................... 26,708 26,057 Accounts receivables, net of allowance for uncollectible accounts of $17,425 and $18,025........................... 120,599 147,787 Other receivables............................................. 44,495 52,158 Inventories................................................... 37,259 36,483 Regulatory assets............................................. 2,740 10,473 Short-term investments........................................ 151,960 45,111 Other current assets.......................................... 31,956 31,428 --------------- -------------- Total current assets........................................ 415,717 349,497 --------------- -------------- Deferred Charges: Regulatory assets............................................. 183,263 197,948 Prepaid benefit costs......................................... 38,724 18,273 Other deferred charges........................................ 46,556 33,726 --------------- -------------- Total current assets........................................ 268,543 249,947 --------------- -------------- $ 2,947,396 $ 2,934,638 =============== ==============
The accompanying notes are an integral part of these financial statements. 5 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
March 31, December 31, 2002 2001 --------------- --------------- (Unaudited) CAPITALIZATION AND LIABILITIES (In thousands) Capitalization: Common stockholders' equity: Common stock................................................... $ 623,149 $ 625,632 Additional paid-in capital..................................... - - Accumulated other comprehensive income, net of tax............. (26,422) (28,996) Retained earnings.............................................. 431,586 415,388 --------------- --------------- Total common stockholders' equity........................... 1,028,313 1,012,024 Minority interest................................................. 11,053 11,652 Cumulative preferred stock without mandatory redemption requirements...................................... 12,800 12,800 Long-term debt, less current maturities........................... 953,897 953,884 --------------- --------------- Total capitalization........................................ 2,006,063 1,990,360 --------------- --------------- Current Liabilities: Short-term debt.................................................... 93,800 35,000 Accounts payable.................................................... 99,592 120,918 Accrued interest and taxes.......................................... 53,050 72,022 Other current liabilities........................................... 87,711 101,697 --------------- --------------- Total current liabilities................................... 334,153 329,637 --------------- --------------- Deferred Credits: Accumulated deferred income taxes................................... 120,359 120,153 Accumulated deferred investment tax credits......................... 43,931 44,714 Regulatory liabilities.............................................. 41,915 52,890 Regulatory liabilities related to accumulated deferred income tax... 14,163 14,163 Accrued postretirement benefit costs................................ 12,733 14,929 Other deferred credits.............................................. 374,079 367,792 --------------- --------------- Total deferred credits....................................... 607,180 614,641 --------------- --------------- $2,947,396 $2,934,638 =============== ===============
The accompanying notes are an integral part of these financial statements. 6 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, -------------------------------- 2002 2001 -------------- -------------- (In thousands) Cash Flows From Operating Activities: Net earnings.......................................................... $ 24,949 $ 63,552 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization..................................... 27,352 25,080 Other, net........................................................ (9,625) 6,462 Changes in certain assets and liabilities: Accounts receivables............................................ 27,188 (33,388) Other assets.................................................... (7,215) 23,630 Accounts payable................................................ (21,326) (40,075) Accrued taxes................................................... (18,972) 49,621 Other liabilities............................................... (6,969) 14,630 -------------- -------------- Net cash flows provided from operating activities............... 15,382 109,512 -------------- -------------- Cash Flows Used for Investing Activities: Utility plant additions............................................... (69,420) (55,820) Return of principal of PVNGS lessor notes............................. 8,996 8,535 Other investing....................................................... (2,055) 109 -------------- -------------- Net cash flows used for investing activities.................... (62,479) (47,176) -------------- -------------- Cash Flows Used for Financing Activities: Borrowings............................................................ 58,800 - Exercise of employee stock options.................................... (2,483) (476) Dividends paid........................................................ (7,970) (7,965) Other financing....................................................... (599) (285) -------------- -------------- Net cash flows provided by (used for) financing activities...... 47,748 (8,726) -------------- -------------- Increase in Cash and Cash Equivalents................................... 651 53,610 Beginning of Period..................................................... 26,057 107,691 -------------- -------------- End of Period........................................................... $ 26,708 $ 161,301 ============== ============== Supplemental Cash Flow Disclosures: Interest paid......................................................... $ 16,183 $ 17,748 ============== ============== Capitalized interest.................................................. $ 1,740 $ - ============== ============== Income taxes paid, net ............................................... $ 38,283 $ 3,400 ============== ============== The accompanying notes are an integral part of these financial statements.
7 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended March 31, ---------------------------- 2002 2001 ------------- ------------- (In thousands) Net Earnings............................................................ $24,949 $63,552 ------------- ------------- Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities: Unrealized holding gains (losses) arising from the period......... 1,822 (948) Less reclassification adjustment for gains (losses) included in net income......................................... (430) (296) Minimum pension liability adjustment................................ - 780 Mark-to-market adjustment for certain derivative transactions: Initial implementation of SFAS 133 designated cash flow hedges.... - 6,148 Change in fair market value of designated cash flow hedges Change in fair market value of designated cash flow hedges........ 615 9,715 Less reclassification adjustment for gains (losses) in cash flow hedges............................................ 568 - ------------- ------------- Total Other Comprehensive Income........................................ 2,575 15,399 ------------- ------------- Total Comprehensive Income.............................................. $27,524 $78,951 ============= =============
The accompanying notes are an integral part of these financial statements. 8 PUBLIC SERVICE COMPANY OF NEW MEXICO CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
Three Months Ended March 31, --------------------------------- 2002 2001 --------------- ------------- (In thousands, except per share amounts) Operating Revenues: Electric..................................... $291,826 $544,594 Gas.......................................... 21,338 191,936 --------------- ------------- Total operating revenues................... 313,164 736,530 --------------- ------------- Operating Expenses: Cost of energy sold.......................... 155,108 497,098 Administrative and general................... 27,825 39,488 Energy production costs...................... 34,971 35,025 Depreciation and amortization................ 24,773 24,219 Transmission and distribution costs.......... 16,537 15,277 Taxes, other than income taxes............... 8,036 7,217 Income taxes................................. 9,772 40,906 --------------- ------------- Total operating expenses................... 277,022 659,230 --------------- ------------- Operating income........................... 36,142 77,300 --------------- ------------- Other Income and Deductions Other........................................ 11,046 4,560 Income tax expense........................... (4,373) (1,926) --------------- ------------- Net other income and deductions............ 6,673 2,634 --------------- ------------- Income before interest charges............. 42,815 79,934 --------------- ------------- Interest charges............................... 17,961 16,382 --------------- ------------- Net Earnings................................... 24,854 63,552 Preferred Stock Dividend Requirements.......... 146 146 --------------- ------------- Net Earnings................................... $ 24,708 $ 63,406 =============== =============
The accompanying notes are an integral part of these financial statements. 9 PUBLIC SERVICE COMPANY OF NEW MEXICO CONSOLIDATED BALANCE SHEETS
March 31, December 31, 2002 2001 ------------------ ----------------- (Unaudited) (In thousands) ASSETS Utility Plant: Electric plant in service..................................... $2,109,993 $2,118,417 Gas plant in service.......................................... 589,097 575,350 Common plant in service and plant held for future use......... 21,021 45,223 ------------------ ----------------- 2,720,111 2,738,990 Less accumulated depreciation and amortization................ 1,247,197 1,234,629 ------------------ ----------------- 1,472,914 1,504,361 Construction work in progress................................. 299,283 249,656 Nuclear fuel, net of accumulated amortization of $19,533 and $16,954....................................... 25,817 26,940 ------------------ ----------------- Net utility plant........................................... 1,798,014 1,780,957 ------------------ ----------------- Other Property and Investments: Other investments............................................. 435,660 446,784 Non-utility property, net of accumulated depreciation of $1,580 for December 31, 2001.............................. 966 1,784 ------------------ ----------------- Total other property and investments........................ 436,626 448,568 ------------------ ----------------- Current Assets: Cash and cash equivalents..................................... 23,008 14,677 Accounts receivables, net of allowance for uncollectible accounts of $17,425 and $18,025........................... 120,599 147,787 Other receivables............................................. 42,211 52,158 Intercompany accounts receivable.............................. 39,336 - Intercompany notes receivable................................. 2,800 - Inventories................................................... 37,245 36,483 Regulatory assets............................................. 2,740 10,473 Short-term investments........................................ 45,407 45,111 Other current assets.......................................... 34,418 21,477 ------------------ ----------------- Total current assets........................................ 347,764 328,166 ------------------ ----------------- Deferred Charges: Regulatory assets............................................. 170,284 187,475 Prepaid benefit costs......................................... 38,724 18,273 Other deferred charges........................................ 58,966 44,199 ------------------ ----------------- Total current assets........................................ 267,974 249,947 ------------------ ----------------- $2,850,378 $2,807,638 ================== =================
The accompanying notes are an integral part of these financial statements. 10 PUBLIC SERVICE COMPANY OF NEW MEXICO CONSOLIDATED BALANCE SHEETS
March 31, December 31, 2002 2001 --------------- --------------- (Unaudited) CAPITALIZATION AND LIABILITIES (In thousands) Capitalization: Common stockholders' equity: Common stock.................................................. $ 195,589 $ 195,589 Additional paid-in capital.................................... 430,043 430,043 Accumulated other comprehensive income, net of tax............ (27,521) (28,996) Retained earnings............................................. 307,598 288,388 --------------- --------------- Total common stockholders' equity.......................... 905,709 885,024 Minority interest................................................ 11,053 11,652 Cumulative preferred stock without mandatory redemption requirements..................................... 12,800 12,800 Long-term debt, less current maturities.......................... 953,898 953,884 --------------- --------------- Total capitalization....................................... 1,883,460 1,863,360 --------------- --------------- Current Liabilities: Short-term debt................................................. 93,800 35,000 Accounts payable................................................. 87,074 120,918 Intercompany accounts payable.................................... 20,515 - Intercompany notes payable....................................... 10,346 - Accrued interest and taxes....................................... 76,596 72,022 Other current liabilities........................................ 78,761 101,697 --------------- --------------- Total current liabilities.................................. 367,092 329,637 --------------- --------------- Deferred Credits: Accumulated deferred income taxes.................................. 134,114 120,153 Accumulated deferred investment tax credits........................ 43,931 44,714 Regulatory liabilities............................................. 41,915 52,890 Regulatory liabilities related to accumulated deferred income tax.. 14,163 14,163 Accrued postretirement benefit costs............................... 13,613 14,929 Other deferred credits............................................. 352,090 367,792 --------------- --------------- Total deferred credits.......................................... 599,826 614,641 --------------- --------------- $2,850,378 $2,807,638 =============== ===============
The accompanying notes are an integral part of these financial statements. 11 PUBLIC SERVICE COMPANY OF NEW MEXICO CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Three Months Ended March 31, ---------------------------------- 2002 2001 -------------- -------------- (In thousands) Cash Flows From Operating Activities: Net earnings......................................................... $ 24,854 $ 63,552 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization.................................... 24,773 25,080 Other, net....................................................... 4,211 6,462 Changes in certain assets and liabilities: Accounts receivables........................................... 27,188 (33,388) Other assets................................................... 17,868 23,630 Accounts payable............................................... (33,844) (40,075) Accrued taxes.................................................. (11,884) 49,621 Other liabilities.............................................. (17,137) 14,630 -------------- -------------- Net cash flows provided from operating activities.............. 36,029 109,512 -------------- -------------- Cash Flows Used for Investing Activities: Utility plant additions.............................................. (67,966) (55,820) Return on PVNGS lease obligation bonds............................... 8,996 8,535 Other investing...................................................... (2,055) 109 -------------- -------------- Net cash flows used for investing activities................... (61,025) (47,176) -------------- -------------- Cash Flows Used for Financing Activities: Borrowings........................................................... 58,800 - Exercise of employee stock options................................... - (476) Dividends paid....................................................... (17,284) (7,965) Other financing...................................................... (520) (285) Change in intercompany accounts...................................... (7,669) - -------------- -------------- Net cash flows provided by (used by) financing activities...... 33,327 (8,726) -------------- -------------- Increase in Cash and Cash Equivalents.................................. 8,331 53,610 Beginning of Period.................................................... 14,677 107,691 -------------- -------------- End of Period.......................................................... $ 23,008 $ 161,301 ============== ============== Supplemental Cash Flow Disclosures: Interest paid........................................................ $ 16,183 $ 17,748 ============== ============== Capitalized interest................................................. $ 1,740 $ - ============== ============== Income taxes paid, net .............................................. $ 31,514 $ 3,400 ============== ==============
The accompanying notes are an integral part of these financial statements. 12 PUBLIC SERVICE COMPANY OF NEW MEXICO CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended March 31, ----------------------------- 2002 2001 ------------- -------------- (In thousands) Net Earnings............................................................. $ 24,854 $63,552 ------------- -------------- Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities: Unrealized holding gains (losses) arising from the period.......... 1,383 (948) Less reclassification adjustment for gains (losses) included in net income.......................................... (430) (296) Minimum pension liability adjustment................................. - 780 Mark-to-market adjustment for certain derivative transactions: Initial implementation of SFAS 133 designated cash flow hedges Change in fair market value of designated cash flow hedges......... - 6,148 Change in fair market value of designated cash flow hedges......... 615 9,715 Less reclassification adjustment for gains (losses) in cash flow hedges............................................. 568 - ------------ -------------- Total Other Comprehensive Income......................................... 2,136 15,399 ------------ -------------- Total Comprehensive Income............................................... $ 26,990 $78,951 ============ ==============
The accompanying notes are an integral part of these financial statements. 13 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Accounting Policies and Responsibilities for Financial Statements In the opinion of management of PNM Resources, Inc. (the "Company") and Public Service Company of New Mexico ("PNM"), the accompanying interim consolidated financial statements present fairly the Company's financial position at March 31, 2002 and December 31, 2001, the consolidated results of its operations for the three months ended March 31, 2002 and 2001 and the consolidated statements of cash flows for the three months ended March 31, 2002 and 2001. 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, 2001, which are included on the Company's Annual Report on Form 10-K for the year ended December 31, 2001. The results of operations presented in the accompanying financial statements are not necessarily representative of operations for an entire year. (2) Presentation The Notes to the Consolidated Financial Statements of the Company and PNM are presented on a combined basis. The Company as an unconsolidated holding company ("Holding Company") assumed substantially all of the corporate activities of PNM on December 31, 2001. These activities are billed to PNM on a cost basis to the extent they are for the corporate management of PNM. In January 2002, Avistar, Inc. ("Avistar") and certain inactive subsidiaries were dividended to PNM Resources, Inc. pursuant to an order from the New Mexico Public Regulatory Commission ("PRC"). The reader of the Notes to the Consolidated Financial Statements should assume that the information presented applies to consolidated results of operations and financial position of both the Company and PNM, except where the context or references clearly indicate otherwise. Discussions regarding specific contractual obligations generally reference the company that is legally obligated. In the case of contractual obligations of PNM, these obligations are consolidated with the Company under Generally Accepted Accounting Principles. Broader operational discussion refers to the Company. Certain amounts in the 2001 consolidated financial statements and notes have been reclassified to conform to the 2002 financial statement presentation. (3) Segment Information The Company is an investor-owned holding company of energy and energy related companies. Its principal subsidiary, PNM, is an integrated public utility primarily engaged in the generation, transmission, distribution and sale and trading of electricity; transmission, distribution and sale of natural gas within the State of New Mexico and the sale and trading of electricity in the Western United States. The Company's wholly-owned subsidiary, Avistar, provides unregulated energy services. 14 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Upon the completion on December 31, 2001, of a one-for-one share exchange between PNM and the Company, the Company became the parent company of PNM. Prior to the share exchange, the Company had existed as a subsidiary of PNM. The new holding company began trading on the New York Stock Exchange under the same PNM symbol beginning on December 31, 2001. As it currently operates, the Company's principal business segments are Utility Operations, which include the Electric Services ("Electric") and the Gas Services ("Gas"), and Generation and Trading Operations ("Generation and Trading"). Electric 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. 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 2,890 circuit miles of transmission lines, interconnected with other utilities in New Mexico and south and east into Texas, west into Arizona, and north into Colorado and Utah. Electric exclusively acquires its electricity sold to retail customers from the Company's Generation and Trading Operations. Intersegment purchases from 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. 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. In the first quarter of 2001, the Company's Generation and Trading Operations procured its gas fuel supply from Gas. In the second quarter of 2001, the Company's Generation and Trading Operations began procuring its gas supply independent of Gas and contracting with Gas for transportation services only. 15 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 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. In addition to generation capacity, the Company purchases power in the open market. As of March 31, 2002 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. 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 and non-utility businesses. Unregulated also includes immaterial corporate activities and eliminations. The immaterial corporate activities were assumed by the Company on December 31, 2001. RISKS AND UNCERTAINTIES The Company's future results may be affected by changes in regional economic conditions; the outcome of labor negotiations with unionized employees; fluctuations in fuel, purchased power and gas prices; the actions of utility regulatory commissions; changes in law and environmental regulations, the success of its planned generation expansion 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. The Company's future results will be impacted by its ability to recover its stranded costs, incurred previously in providing power generation to electric service customers, the market price of electricity and natural gas costs and the costs of transition to an unregulated status. In addition, as a result of deregulation, the Company may face competition from companies with greater financial and other resources. 16 Summarized financial information by business segment for the three months ended March 31, 2002 and 2001 is as follows:
Utility ------------------------------- Generation Electric Gas Total and Trading Unregulated Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 2002: Operating revenues: External customers............ $135,243 $ 109,086 $244,329 $ 68,720 $ 832 $313,881 Intersegment revenues......... 177 115 292 81,950 (82,127) 115 Depreciation and amortization.... 8,555 5,312 13,867 10,907 5 24,779 Interest income.................. 318 88 406 402 15,451 16,259 Net interest charges............. 5,835 3,318 9,153 3,468 2,505 15,126 Income tax expense From continuing operations..... 5,936 5,711 11,647 1,301 1,260 14,208 Operating income (loss).......... 15,017 12,093 27,110 5,623 (46) 32,687 Segment net income (loss)........ 9,059 8,714 17,773 1,985 5,191 24,949 Total assets..................... 762,747 457,934 1,220,681 1,418,564 308,151 2,947,396 Gross property additions......... 12,856 6,543 19,399 48,545 1,476 69,420
Utility ------------------------------ Generation Electric Gas Total and Trading Unregulated Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 2001: Operating revenues: External customers............. $134,346 $190,686 $325,032 $410,248 $ - $735,280 Intersegment revenues.......... 177 1,250 1,427 80,917 (81,094) 1,250 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 2,985 7,258 9,094 30 16,382 Income tax expense (benefit) from continuing operations...... 6,899 5,162 12,061 35,183 (4,412) 42,832 Operating income (loss)........... 14,526 10,507 25,033 58,106 (5,839) 77,300 Segment net income (loss)......... 10,410 7,736 18,146 53,596 (8,190) 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
(4) Financial Instruments The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices, interest rates of future debt issuances 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. 17 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The Company is exposed to credit risk in the event of non-performance or non-payment by counterparties of its financial derivative instruments. 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, 2002 was $4.3 million. Natural Gas Contracts Pursuant to a 1997 order issued by the NMPUC, predecessor to the PRC, PNM has previously entered into various financial instruments to hedge certain portions of natural gas supply contracts in order to protect PNM's natural gas customers from the risk of adverse price fluctuations in the natural gas market. The financial impact of all hedge gains and losses from these instruments is recoverable through PNM's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by gains or losses generated by these instruments. PNM purchased gas options, a type of hedge, to protect its natural gas customers from price risk during the 2001-2002 heating season. PNM expended $9.4 million to purchase options that limit the maximum amount PNM would pay for gas during the winter heating season. PNM recovered its actual hedging expenditures as a component of the PGAC during the months of October 2001 through February 2002 in equal allotments of $1.88 million. As winter 2001-2002 gas prices were substantially lower than the previous year, the hedges placed for this winter expired unexercised. PNM also purchased gas options for the 2002-2003 heating season. PNM expended $6.0 million to purchase options that limit the maximum amount PNM would pay for gas during the winter heating season. PNM plans to recover its actual hedging expenditures as a component of the PGAC during the months of October 2002 through February 2003 in equal allotments of $1.2 million. Electricity Trading Contracts For the three months ended March 31, 2002, the Company's Generation and Trading Operations settled trading contracts for the sale of electricity that generated $7.8 million of electric revenues by delivering 222,096 MWh. The Company purchased $17.0 million or 276,896 MWh of electricity to support these contractual sales and other open market sales opportunities. For the three months ended March 31, 2001, the Company's Generation and Trading Operations settled trading contracts for the sale of electricity that generated $11.8 million of electric revenues by delivering 122,000 MWh. The Company purchased $10.9 million or 102,400 MWh of electricity to support these contractual sales and other open market sales opportunities. As of March 31, 2002, the Company had open trading contract positions to buy $63.0 million and to sell $31.2 million of electricity. At March 31, 2002, the Company had a gross mark-to-market gain (asset position) on these trading contracts of $7.6 million and gross mark-to-market loss (liability position) of $28.5 million, with net mark-to-market loss (liability position) of $20.9 million. The change in mark-to-market valuation is recognized in earnings each period. 18 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) In addition, the Company's Generation and Trading Operations enter into forward physical contracts for the sale of the Company's electric capacity in excess of its jurisdictional needs, including reserves, or the purchase of jurisdictional needs, including reserves, when resource shortfalls exist. The Company generally accounts for these derivative financial instruments as normal sales and purchases as defined by SFAS 133, as amended. 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, 2002, the Company had open forward positions classified as normal sales of electricity of $16.3 million and normal purchases of electricity of $42.9 million. The Company's Generation and Trading 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. Forward Starting Interest Rate Swaps PNM currently has $182.0 million of tax-exempt bonds outstanding that are callable at a premium in December 2002 and August 2003. PNM intends to refinance these bonds assuming the interest rate of the refinancing does not exceed the current interest rate of the bonds and has hedged the entire planned refinancing. In order to take advantage of current low interest rates, PNM entered into two forward starting interest rate swaps in November and December 2001 and three additional contracts in the first quarter of 2002. PNM designated these swaps as cash flow hedges. The hedged risks associated with these instruments are the changes in cash flows related to general moves in interest rates expected for the refinancing. The swaps effectively cap the interest on the refinancing to 4.9% plus an adjustment for PNM's and the industry's credit rating. PNM's assessment of hedge effectiveness is based on changes in the interest rates and PNM's credit spread. 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 transactions affect earnings. Any hedge ineffectiveness is required to be presented in current earnings. There was no material hedge ineffectiveness in the three months ended March 31, 2002. A forward starting swap does not require any upfront premium and captures changes in the corporate credit component of an investment grade company's interest rate as well as the underlying Treasury benchmark. The five forward interest rate starting swaps have termination dates and notional amounts as follows: one with a termination date of September 17, 2002 for a notional amount of $46.0 million and four with a termination date of May 15, 2003 for a combined notional amount of $136.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transactions will be cash settled on the mandatory unwind date (strike date), corresponding to the refinancing date of the underlying debt. The settlement will be capitalized as a cost of issuance and amortized over the life of the debt as a yield adjustment. 19 PNM RESOURCES, INC. 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, 2002 2001 ----------- ----------- Basic: Net Earnings from Continuing Operations................ $ 24,949 $ 63,552 ----------- ----------- Net Earnings........................................... 24,949 63,552 Preferred Stock Dividend Requirements.................. 146 146 ----------- ----------- Net Earnings Applicable to Common Stock................ $ 24,803 $ 63,406 =========== =========== Average Number of Common Shares Outstanding............ 39,118 39,118 =========== =========== Net Earnings per Common Share (Basic).................. $ 0.63 $ 1.62 =========== =========== Diluted: Net Earnings Applicable to Common Stock Used in basic calculation............................ $ 24,803 $ 63,406 =========== =========== Average Number of Common Shares Outstanding............ 39,118 39,118 Dilutive effect of common stock equivalents (a)........ 531 481 ----------- ----------- Average common and common equivalent shares Outstanding.......................................... 39,649 39,599 =========== =========== Net Earnings per Share of Common Stock (Diluted)....... $ 0.63 $ 1.60 =========== =========== (a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of 14,000 for the three months ended March 31, 2002. There were no anti-dilutive common stock equivalents in 2001. 20 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) Commitments and Contingencies Construction Commitment PNM has committed to purchase five combustion turbines for a total cost of $151.3 million. The turbines are for planned power generation plants with an estimated cost of construction of approximately $370 million. PNM has expended $160 million as of March 31, 2002 of which $117.2 million was for equipment purchases. In November 2001, PNM broke ground to build Afton Generating Station, a 135 MW single cycle gas turbine plant in Southern New Mexico. In February 2002, PNM broke ground to build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired generating plant in Southern New Mexico. In January of 2002, the Lordsburg City Council approved the issuance of industrial revenue bonds for Lordsburg. Contracts have not been finalized on the remaining planned construction. These plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. This construction is not anticipated to be added to rate base. 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. Aspects of the Federal law referred to above (the "Price-Anderson Act"), which provides for payment of public liability claims in case of a catastrophic accident involving a nuclear power plant are up for renewal in August 2002. While existing nuclear power plant would continue to be covered in any event, the renewal would extend coverage to future nuclear power plants and could contain amendments that would affect existing plants. A renewal bill was passed by the House with unanimous consent on November 27, 2001. The House proposed a change in the annual retrospective premium limit from $10 million to $15 million per reactor per incident. Additionally, the House proposed to amend the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident, taking into account effects of inflation. On March 7, 2002 the Senate approved a Price-Anderson Act amendment as a part of the overall energy bill. The Senate version is substantially the same as the Price-Anderson Act in its current form. In the event the energy bill does not pass, it is possible that the Price-Anderson amendment would be passed as a stand-alone bill. In a report issued in 1998, the Nuclear Regulatory Commission ("NRC") had made a number of recommendations regarding the Price-Anderson Act, including a recommendation that Congress investigate whether the $200 million now available from the private insurance market for liability claims per reactor could be increased to keep pace with inflation. The Company cannot predict whether or not Congress will renew the Price-Anderson Act or act on the NRC's recommendation. However, 21 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) if adopted, certain changes in the law could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by the lessors. Such an occurrence could require the Company to, among other things, (i) pay the lessor and the equity investor, in return for the investor's interest in PVNGS, cash in the amount as provided in the lease and (ii) assume debt obligations relating to the PVNGS lease. 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, 2002, a substantial portion of which must be applied to stabilization and decontamination. The Company has also secured insurance against portions of the increased cost of generation or purchased power and business interruption resulting from certain accidental outages of any of the three units if the outages exceed 12 weeks. The insurance coverage discussed in this section is subject to certain policy conditions and exclusions. The Company is a member of an industry mutual insurer. This mutual insurer 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 $4.8 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 decommissioning costs excluding spent fuel disposal would be approximately $181 million (in 1998 dollars). The estimated market value of the trusts at the end of March 31, 2002 was approximately $58 million. The Company did not provide any additional funding for the three months ended March 31, 2002 into the qualified and non-qualified trust funds. 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 22 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 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 $ 41.0 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. 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. The Company's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. The Company also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau, which issued its report on March 18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the Company by the injured persons along with several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur as a result of the Pipeline Safety Bureau's investigation. 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. Western Resources Transaction On November 9, 2000, the Company and Western Resources announced that both companies' Boards of Directors approved an agreement under which the Company would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing. In July, 2001, the Kansas Corporation Commission ("KCC") issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger. Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by 23 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001 in New York state court seeking declarations that the transaction could not be accomplished as designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. On November 19, 2001, Western Resources filed a complaint against the Company in New York state court alleging breach of contract and breach of implied covenant of good faith and fair dealing. Western Resources alleged that the Company brought about the KCC orders, failed to assist in efforts to reverse the KCC orders, refused to renegotiate within the terms of the agreement, interfered with Western Resources' efforts to satisfy the terms of the agreement, and effected an unauthorized de facto termination of the agreement by filing its complaint. Western Resources alleges damages in excess of $650 million. The Company believes that the complaint filed by Western Resources is without merit and intends to vigorously defend itself against the complaint. The Company also intends to vigorously pursue its own complaint. On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. On February 5, 2002, the District Court for Shawnee County, Kansas, dismissed without prejudice Western Resources' appeal of the KCC's split-off orders. The Court ruled that, by filing a new financial plan in compliance with the orders, Western Resources accepted certain portions of the orders thereby creating a situation where further administrative action became necessary. As a result, the Court concluded that the matter was not ripe for judicial review and remanded the case to the KCC. On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate order. On April 8, 2002, Western Resources filed with the Kansas Supreme Court a Petition for Review of the Court of Appeals decision. On May 2, 2002, the New York court issued an order denying Western Resources' motion for stay or dismissal of the Company's complaint. At the same time, the court granted the Company's motion to dismiss Western Resources' complaint, without prejudice. As a result, the Company has been determined to be the plaintiff in the litigation but Western Resources will be allowed, when it files its answer, to reassert its claims against the Company as affirmative defenses or counterclaims, if it so chooses. On May 10, 2002, the Company filed an Amended Complaint seeking unspecified damages from Western Resources for numerous breaches of contract related to the determination that the split-off required by the agreement was unlawful and required prior approval by the KCC. The Company also seeks unspecified damages for additional breaches of contract because: Western Resources failed to provide the Company with the opportunity to review and comment on information related to the transaction provided by Western Resources 24 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) to third parties; Western Resources failed to obtain the Company's consent to amend existing employee compensation and benefits plans or create new ones; and Western Resources filed for approval of an alternative debt reduction plan that represents the abandonment of the split-off required by the agreement. In addition the Company seeks numerous declarations from the court, including that the Company was not obligated to perform because conditions regarding performance were not satisfied; the Company did not breach when it terminated the agreement; and the rate case order constitutes a material adverse effect under the terms of the agreement. The Company is unable to predict the ultimate outcome of its litigation with Western Resources. 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 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). 25 PNM RESOURCES, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 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. For the three months ended March 31, 2002 and 2001, the Company spent $1.3 million and $1.4 million, respectively, for remediation. The majority of the March 31, 2002 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) New and Proposed Accounting Standards Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). In June 2001, the FASB issued SFAS 143. The statement requires the recognition of a liability for legal obligations associated with the retirement of a tangible long-lived asset that result from the acquisition, construction or development and/or the normal operation of a long-lived asset. The asset retirement obligation is required to be recognized at its fair value when incurred. The cost of the asset retirement obligation is required to be capitalized by increasing the carrying amount of the related long-lived asset by the same amount as the liability. This cost must be expensed using a systematic and rational method over the related asset's useful life. SFAS 143 is effective for the Company beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and is unable to predict its impact on the Company's operating results and financial position at this time. Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the FASB issued SFAS 144. The statement amends certain requirements of the previously issued pronouncement on asset impairment, SFAS 121. SFAS 144 removes goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by "Accounting Principles Board Opinion No. 30." Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position. 26 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Management's Discussion and Analysis of Financial Condition and Results of Operations for PNM Resources, Inc. (the "Company") and Public Service Company of New Mexico ("PNM") is presented on a combined basis. The Company as an unconsolidated holding company ("Holding Company") assumed substantially all of the corporate activities of PNM on December 31, 2001. These activities are billed to PNM on a cost basis to the extent they are for the corporate management of PNM. In January 2002, Avistar and certain inactive subsidiaries were dividended to PNM Resources, Inc. pursuant to an order from the PRC. The reader of this Management's Discussion and Analysis of Financial Condition and Results of Operations should assume that the information presented applies to consolidated results of operations and financial position of both the Company and PNM, except where the context or references clearly indicate otherwise. Discussions regarding specific contractual obligations generally reference the company that is legally obligated. In the case of contractual obligations of PNM, these obligations are consolidated with the Company under Generally Accepted Accounting Principles ("GAAP"). Broader operational discussion references the Company. 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 its annual report on Form 10-K for the year ended December 31, 2001. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. OVERVIEW The Company is an investor-owned holding company of energy and energy related companies. Its principal subsidiary, PNM, is an integrated public utility primarily engaged in the generation, transmission, distribution and sale and trading of electricity; transmission, distribution and sale of natural gas within the State of New Mexico and the sale and trading of electricity in the Western United States. The Company's principal business segments are Utility Operations, which include Electric Services ("Electric") and Gas Services ("Gas"), and Generation and Trading Operations ("Generation and Trading"). Electric 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 business line. The Company's wholly-owned subsidiary, Avistar, Inc. ("Avistar"), provides unregulated energy services. Upon the completion on December 31, 2001, of a one-for-one share exchange between PNM and the Company, the Company became the parent company of PNM. Prior to the share exchange, the Company had existed as a subsidiary of PNM. The new holding company began trading on the New York Stock Exchange under the same PNM symbol beginning on December 31, 2001. 27 COMPETITIVE STRATEGY The Company is positioned as a "merchant utility," primarily operating as a regulated energy service provider also engaged in the sale and trading of electricity in the competitive energy market place. As a utility, the Company has an obligation to serve its customers under the jurisdiction of the New Mexico Public Regulation Commission ("PRC"). As a merchant, the Company markets excess production from the utility, as well as unregulated generation and its purchases for resale into a competitive market place. The merchant operations utilize an asset-backed trading strategy, whereby the Company's aggregate net open position for the sale of electricity is covered by the Company's excess generation capabilities. The benefits of the merchant operations are shared with retail customers based on a negotiated settlement in proportion to capacity owned, expended effort, and risk assumed. Non-regulated assets may be part of the utility company or owned by an affiliate of the utility company, which could be a subsidiary of the holding company. Currently, all non-regulated assets, except Avistar, are part of the utility. Both retail customers and shareholders benefit from this combination. The Electric and Gas Services strategy is directed at supplying reasonably priced and reliable energy to retail customers through customer driven operational excellence, quality processes, and improved overall organizational performance. The Generation and Trading strategy calls for increased asset-backed trading and generation capacity supported by long-term contracts, as well as improved risk management strategies. The Company's plans to increase generation calls for approximately 50% of its new generation and 70% of its total portfolio to be committed through long-term contracts, including its sales to jurisdictional customers. Such growth will be dependent on market developments, and upon the Company's ability to generate funds for the Company's expansion. (Intentionally left blank) 28 RESULTS OF OPERATIONS Three Months Ended March 31, 2002 Compared to Three Months Ended March 31, 2001 Consolidated The Company's net earnings available to common shareholders for the three months ended March 31, 2002 were $24.8 million, a 60.9% decrease in net earnings of $63.4 million in 2001. This decrease primarily reflects the slowdown in the wholesale electric market, where both prices and trading activity were lower than the prior year period. Despite the slow-down in the wholesale electricity market, the Company's utility operations continued to perform strongly and recorded operating income growth of 18%. This growth came from a combination of load growth and cost savings, demonstrating the balance the regulated utility provides in the Company's "merchant utility" strategy. Earnings in 2001 were affected by certain non-recurring charges. These special items are detailed in the individual business segment discussions below. The following table enumerates these non-recurring charges and shows their effect on diluted earnings per share, in thousands, except per share amounts.
Three Months Ended March 31, ------------------------------------------------------------ 2002 2001 ---------------------------- ------------------------------ EPS EPS Earnings (Diluted) Earnings (Diluted) -------------- ------------- --------------- -------------- (Income)/Expense Net Earnings Available for Common Shareholders............................. $ 24,803 $0.63 $ 63,406 $1.60 -------------- ------------- --------------- -------------- Adjustment for Special Gains and Charges (net of income tax effects): Write-off of Avistar investments.......... - - 4,981 0.13 Western Resources acquisition costs....... - - 1,817 0.05 -------------- ------------- -------------- -------------- Total................................... - - 6,798 0.18 -------------- ------------- -------------- -------------- Net Earnings Available For Common Shareholders Excluding Special Gains and Charges $ 24,803 $0.63 $ 70,204 $1.78 ============== ============= ============== ==============
To adjust reported net earnings and diluted earnings per share to exclude the non-recurring charges, non-recurring charges, net of income tax benefit, are added back to reported net earnings under GAAP. 29 The following discussion is based on the financial information presented in the Consolidated Financial Statements - Segment Information note in the Notes to the Consolidated Financial Statements. Utility Operations Electric The table below sets forth the operating results for the Electric business segment.
Electric Three Months Ended March 31, ---------------------------------- 2002 2001 Variance ------------- -------------- -------------- Operating revenues: External customers............................. $135,243 $134,346 $ 897 Intersegment revenues.......................... 177 177 - ------------- -------------- -------------- Total revenues................................. 135,420 134,523 897 ------------- -------------- -------------- Cost of energy sold.............................. 1,192 1,560 (368) Intersegment purchases........................... 81,950 80,917 1,033 ------------- -------------- -------------- Total cost of energy........................... 83,142 82,477 665 ------------- -------------- -------------- Gross margin..................................... 52,278 52,046 232 ------------- -------------- -------------- Administrative and general....................... 8,372 10,266 (1,894) Corporate costs.................................. 2,403 1,566 837 Energy production costs.......................... 229 310 (81) Depreciation and amortization.................... 8,555 8,025 530 Transmission and distribution costs.............. 8,512 8,107 405 Taxes other than income taxes.................... 3,173 2,527 646 Income taxes..................................... 6,017 6,719 (702) ------------- -------------- -------------- Total non-fuel operating expenses.............. 37,261 37,520 (259) ------------- -------------- -------------- Operating income................................. $ 15,017 $ 14,526 $ 491 ------------- -------------- --------------
Operating revenues increased $0.9 million or 0.7% for the period to $135.4 million. Retail electricity delivery grew 1.2% to 1.74 million MWh in 2002 compared to 1.72 million MWh delivered in the prior year period, resulting in increased revenues of $2.2 million year-over-year. This volume increase was the result of consistent load growth from economic expansion in New Mexico. This increase was partially offset by lower revenue from property leasing. (Intentionally left blank) 30 The following table shows electric revenues by customer class and average customers: Electric Revenues (Thousands of dollars) Three Months Ended March 31, ---------------------------- 2002 2001 ------------- ------------ Residential..................... $50,722 $49,197 Commercial...................... 55,005 54,137 Industrial...................... 19,628 19,837 Other........................... 10,065 11,352 ------------- ------------ $135,420 $134,523 ============= ============ Average Customers............... 382,000 375,000 ============= ============ The following table shows electric sales by customer class: Electric Sales (Megawatt hours) Three Months Ended March 31, ----------------------------- 2002 2001 ------------ ------------ Residential..................... 588,996 572,199 Commercial...................... 711,259 713,198 Industrial...................... 392,346 388,135 Other........................... 46,874 45,033 ------------ ------------ 1,739,475 1,718,565 ============ ============ The gross margin, or operating revenues minus cost of energy sold, increased $0.2 million, which reflects the increased energy sales. Electric exclusively purchases power from Generation and Trading at Company developed prices which are not based on market rates. These intercompany revenues and expenses are eliminated in the consolidated results. Administrative and general costs decreased $1.9 million or 18.4% for the period. This decrease was primarily due to lower bad debt expense as a result of losses recognized in the prior year from the bankruptcy of a significant customer that did not recur in 2002 and decreased pension and post-retirement benefits expense. In 2001, the Company's pension and post-retirement benefits expense was significantly higher than what the Company historically experienced due to lower expected investment returns on plan assets. As a result of more normal expected investment returns and the Company's cash contributions of $23.5 million to its plans in January 2002, pension and post retirement benefits expense in 2002 was substantially reduced as compared to 2001. Depreciation and amortization increased $0.5 million or 6.6% for the period due to a higher depreciable plant base. 31 Transmission and distribution costs increased $0.4 million or 5.0% primarily due to an increase in maintenance activities on station equipment and overhead lines. Taxes other than income increased $0.6 million or 25.6% primarily reflecting adjustments recorded in the prior year for favorable audit outcomes by certain tax authorities. Gas The table below sets forth the operating results for the Gas business segment.
Gas Three Months Ended March 31, ------------------------------- 2002 2001 Variance ------------- -------------- -------------- perating revenues: External customers............................. $109,086 $190,686 $(81,600) Intersegment revenues.......................... 115 1,250 (1,135) ------------- -------------- -------------- Total revenues................................. 109,201 191,936 (82,735) ------------- -------------- -------------- Total cost of energy........................... 64,749 148,472 (83,723) ------------- -------------- -------------- Gross margin..................................... 44,452 43,464 988 ------------- -------------- -------------- Administrative and general....................... 8,648 12,349 (3,701) Corporate costs.................................. 2,145 1,307 838 Energy production costs.......................... 531 431 100 Depreciation and amortization.................... 5,312 5,290 22 Transmission and distribution costs.............. 7,930 7,056 874 Taxes other than income taxes.................... 2,043 1,596 447 Income taxes..................................... 5,750 4,928 822 ------------- -------------- -------------- Total non-fuel operating expenses.............. 32,359 32,957 (598) ------------- -------------- -------------- Operating income................................. $ 12,093 $10,507 $ 1,586 ------------- -------------- --------------
Operating revenues decreased $82.7 million or 43.1% for the period to $109.2 million, primarily as the result of lower natural gas prices during the first quarter of 2002 as compared to the same period in the previous year. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, increases or decreases in gas revenues driven by gas costs do not impact the Company's gross margin or earnings. Gas sales volumes decreased 5.0% contributing to the decreased revenues. However, residential and commercial volume increased 10.8% due to load growth from economic expansion in New Mexico. (Intentionally left blank) 32 The following table shows gas revenues by customer and average customers: Gas Revenues (Thousands of dollars) Three Months Ended March 31, ------------------------------ 2002 2001 ------------- ------------- Residential....................... $72,112 $121,589 Commercial........................ 22,399 36,797 Industrial........................ 649 13,537 Transportation*................... 3,611 4,002 Other............................. 10,430 16,011 ------------- ------------- $109,201 $191,936 ============= ============= Average customers................. 444,000 435,000 ============= ============= The following table shows gas throughput by customer class: Gas Throughput (Thousands of decatherms) Three Months Ended March 31, ----------------------------- 2002 2001 ------------ ------------ Residential........................ 13,516 12,481 Commercial......................... 4,970 4,207 Industrial......................... 172 1,980 Transportation*.................... 7,397 9,178 Other.............................. 1,990 1,667 ------------ ------------ 28,045 29,513 ============ ============ *Customer-owned gas. The gross margin, or operating revenues minus cost of energy sold, increased $1.0 million or 2.3%. This increase is due mainly to residential and commercial customer load growth in the New Mexico service territory. Administrative and general costs decreased $3.7 million or 30.0%. This decrease is primarily due to lower bad debt expense as a result of losses recognized in the prior year from the bankruptcy of a significant customer that did not recur in 2002 and the decreased pension and post-retirement benefits as discussed earlier. Transmission and distribution costs increased $0.9 million or 12.4 % primarily due to the timing of certain maintenance costs that are typically incurred in the summer months. It is expected that the Company's maintenance costs will be lower in the summer months. 33 Generation and Trading Operations The table below sets forth the operating results for the Generation and Trading business segment.
Generation and Trading Three Months Ended March 31, ------------------------------------- 2002 2001 Variance ------------- -------------- -------------- Operating revenues: External customers............................. $ 68,720 $410,248 $(341,528) Intersegment revenues.......................... 81,950 80,917 1,033 ------------- -------------- -------------- Total revenues................................. 150,670 491,165 (340,495) ------------- -------------- -------------- Cost of energy sold.............................. 89,167 347,066 (257,899) Intersegment purchases........................... 177 177 - ------------- -------------- -------------- Total cost of energy........................... 89,344 347,243 (257,899) ------------- -------------- -------------- Gross margin..................................... 61,326 143,922 (82,596) ------------- -------------- -------------- Administrative and general....................... 4,153 5,120 (967) Corporate costs.................................. 2,105 1,365 740 Energy production costs.......................... 34,211 34,284 (73) Depreciation and amortization.................... 10,907 10,895 12 Transmission and distribution costs.............. 95 113 (18) Taxes other than income taxes.................... 2,820 1,921 899 Income taxes..................................... 1,412 32,118 (30,706) ------------- -------------- -------------- Total non-fuel operating expenses.............. 55,703 85,816 (30,113) ------------- -------------- -------------- Operating income................................. $ 5,623 $58,106 $(52,483) ------------- -------------- --------------
Operating revenues declined $340.5 million or 69.3% for the period to $150.7 million. This decrease in wholesale electricity sales primarily reflects the slowdown in the wholesale electric market, where both prices and trading activity were lower than the prior year period. Lower trading activity experienced by Generation and Trading was also due to decreased plant availability which resulted in lost market potential. The Company's plants' capacity was 11.6% less than the prior year due to various unplanned outages. The Company delivered wholesale (bulk) power of 4.1 million MWh of electricity for the first quarter of 2002, compared to 4.9 million MWh for the same period in 2001. Wholesale revenues from third-party customers decreased from $410.7 million to $56.3 million, an 86.3% decrease. (Intentionally left blank) 34 The following table shows revenues by customer class: Generation and Trading Revenues By Market (Thousands of dollars) Three Months Ended March 31, -------------------------------- 2002 2001 --------------- --------------- Intersegment sales.................. $ 81,950 $ 80,917 Long-term contract.................. 14,337 28,814 Trading*............................ 51,476 378,051 Other............................... 2,907 3,383 --------------- --------------- $ 150,670 $ 491,165 =============== =============== *Includes mark-to-market gains/(losses). The following table shows sales by customer class: Generation and Trading Sales By Market (Megawatt hours) Three Months Ended March 31, ------------------------------- 2002 2001 ------------- -------------- Intersegment sales.................. 1,739,475 1,718,565 Long-term contract.................. 281,153 478,053 Trading............................. 2,060,242 2,680,078 ------------- -------------- 4,080,870 4,876,696 ============= ============== The gross margin, or operating revenues minus cost of energy sold, decreased $82.6 million or 57.4%. Lower margins were created primarily by weak pricing, less price volatility and lower trading liquidity - the opportunity to buy and resell power profitably in the marketplace. Trading liquidity was negatively impacted in the first quarter of 2002 due to the bankruptcy of a major trader in 2001, the price caps imposed by the Federal Energy Regulation Commission ("FERC") and the Company's plant availability. Although the wholesale market showed some forward price improvement towards the end of the quarter the Company was unable to take advantage of this due to plant availability. These lower margins were partially offset by an increase in unrealized mark-to-market gains of $5.7 million period-over-period which the Company recognized relating to its power trading contracts. Administrative and general costs decreased $1.0 million or 18.9% for the period. This decrease is primarily due to adjustments to prior year San Juan Generating Station ("SJGS") participant billings (the Company is the operator of SJGS) and the lower pension and post-retirement benefits expense discussed earlier. 35 Energy production costs remained relatively constant in 2002 as compared to 2001. The Company experienced significant costs related to various planned and unplanned outages at SJGS, Palo Verde Generating Station ("PVNGS") and Four Corners Power Plant ("Four Corners"). However, the Company was able to benefit from the acceleration of its usual first quarter outage in the third quarter of 2001. In addition, these costs were offset by adjustments to prior year billings for estimated costs by the PVNGS operator of $3.7 million. Taxes other than income increased $0.9 million or 46.8% reflecting adjustments recorded in the prior year for favorable audit outcomes by certain tax authorities. Unregulated Businesses In July 2001, the Board of Directors of Avistar decided to wind down all unregulated operations except for Avistar's Reliadigm business unit, which provides maintenance solutions and technologies to the electric power industry. In addition, the transfer of operation of the Sangre de Cristo Water Company to the City of Santa Fe was completed in the third quarter. All remaining non-Reliadigm investments were written-off with the exception of Avistar's investment in Nth Power, an energy related venture capital fund. These write-downs reflect the significant decline in the technology market and bankruptcy of these investees. The Company recorded non-operating charges of $8.3 million for the three months ended March 31, 2001 to reflect these activities and the impairment of its Avistar investments. This charge was recorded in other income and deductions. Operating losses for Avistar decreased from $1.3 million in the prior period to $0.4 million in the current period primarily due to decreased costs as a result of the shutdown of certain operations. Corporate Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, decreased $0.2 million for the period to $9.6 million. This decrease was primarily due to lower bonus expense in the current year resulting from lower earnings. Other Non-Operating Other income and deductions, net of taxes, increased $4.8 million for the period to $7.4 million primarily due to charges in 2001 that did not recur in 2002. On a pre-tax basis in 2001, the Company recognized charges of $8.3 million to write-off certain permanently impaired Avistar investments and costs of $1.0 million related to the Company's terminated acquisition of Western Resources' electric utility operations, partially offset by $3.4 million of equity income from a passive investment. The current year also had a decrease in investment income of $0.3 million on the PVNGS decommissioning trust assets. The Company's consolidated income tax expense was $14.2 million for the three months ended March 31, 2002, compared to $42.8 million for the three months ended March 31, 2001. The impact of lower earnings in 2002 contributed to the difference. The Company's effective income tax rates for the three months ended March 31, 2002 and 2001 were 36.28% and 40.26%, respectively. Included in the Company's 2001 taxable income were 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% in 2001. The decrease in the effective rate was primarily due to adjustments to the Company's prior year tax returns for certain research and development credits. 36 FUTURE EXPECTATIONS On April 24, 2002, the Company announced that it was revising its 2002 earnings expectations. The Company now expects full year 2002 earnings to be in the range of $2.60 to $2.85. This earnings guidance is affected by three primary factors. Average wholesale prices in the West are expected to be lower than previously projected by the Company. In addition, the Company expects liquidity to return to the wholesale marketplace at lower levels than previously anticipated. Accordingly, lower liquidity in the wholesale market will affect the Company's ability to buy and resell power leading to a lower ratio of total sales to generation. Finally, the Company revised its outlook on forward spark spreads, the difference between the cost of gas generation and the wholesale price of electricity. Because the Company's current gas generation assets are essentially peaking resources, earnings contribution from these resources occurs only when the spark spread exceeds approximately $15 per MWh. The Company is now assuming spark spreads to remain below the level necessary to justify use of its gas generation. Consequently, the revised earnings guidance presumes that there will be no earnings contributions from the Company's gas peaking resources. The calculation of future expected earnings is also subject to numerous variables, including on and off-peak wholesale demand, retail load needs, generating resource availability, the current position of the Company's trading portfolio and general economic conditions. While the Company manages the short-term impacts of the current wholesale market, it remains committed to the implementation of its strategic plan. The Company is proceeding with the construction of two new generating plants in southern New Mexico. Because transmission constraints make it difficult to import power into that area, the Company believes these new plants are a sound long-term investment. The Company is currently looking beyond New Mexico for additional resources, and it is looking to buy existing assets rather than building, because the current downturn in power prices has made assets available at more attractive prices. As a result of the reduced pricing environment, many generators have announced the cancellation of previously planned projects. The Company expects that forward prices will again move upward in future periods as a result of under building and overall increased demand for electricity. As the Company adds new generation resources, it is expected that earnings will trend upwards as sales volumes grow. This earnings growth is expected to be in high single digits over the long-term. 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 that could cause the Company's actual financial results to differ materially from the expected results enumerated above. LIQUIDITY AND CAPITAL RESOURCES At March 31, 2002, the Company had cash and short-term investments of $178.7 million compared to $176.8 million in cash, short-term and long-term investments at December 31, 2001. Certain long-term investments have been reclassified as short-term to reflect the Company's liquidity needs to fund certain construction projects in 2002. 37 Cash provided from operating activities in the three months ended March 31, 2002 was $15.4 million compared to cash provided by operating activities of $109.5 million for the three months ended March 31, 2001. The Company did not make its first quarter 2001 estimated federal income tax payment until January 2002 because of an extension granted by the IRS to taxpayers in several counties in New Mexico as a result of wildfires in 2000. This out-of-period income tax payment reduced operating cash flows below normal levels. Cash used for investing activities was $62.5 million in 2002 compared to $47.2 million in 2001. Cash used for investing activities includes construction expenditures for new generating plants of $48.1. The decline in expenditures reflects the acquisition of certain transmission assets and other related investing activities of $13.9 which did not recur in 2002. Cash generated by financing activities was $47.7 million in 2002 compared to $8.7 million of cash used in 2001. Financing activities in 2002 were primarily short-term borrowings for liquidity reasons, partially offset by cash payments for dividend requirements. The use of cash in 2001 primarily reflects cash payments for dividend requirements. Pension and Other Postretirement Benefits In 2001, the investment market experienced significant declines due to various reasons. As a result, the Company adjusted the expected rate of return on its pension and other postretirement benefit plans assets. In 2002, the Company expects its rate of return on plan assets will return to historic levels. For the three months ended March 31, 2002, the Company's net periodic benefit cost assumed a 7.75% rate of return as compared to 9.00% in the prior year. In addition, in January 2002, the Company made an aggregate contribution of $23.5 million to fund the pension and other postretirement benefit plans. The effect of this contribution was to reduce the impact that the actual investment losses will have on the Company's future net periodic benefit cost. The effect of the change in expected rate of return and the additional cash contribution was a decrease in pension and other post retirement benefits expense of $3.0 million for the quarter ended March 31, 2002. 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 wholesale generation capabilities. Projections for total capital requirements for 2002 are $409 million and projections for construction expenditures for 2002 are $391 million. For 2002-2006 projections, total capital requirements are $1.9 billion and construction expenditures are $1.8 billion, including the combustion turbines discussed below. These estimates are under continuing review and subject to on-going adjustment. 38 PNM has committed to purchase five combustion turbines for a total cost of $151.3 million. The turbines are for planned power generation plants with an estimated cost of construction of approximately $370 million. PNM has expended $160 million as of March 31, 2002 of which $117.2 million was for equipment purchases. In November 2001, PNM broke ground to build Afton Generating Station, a 135 MW single cycle gas turbine plant in Southern New Mexico. In February 2002, PNM broke ground to build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired generating plant in Southern New Mexico. In January of 2002, the Lordsburg City Council approved the issuance of industrial revenue bonds for Lordsburg and on February 28, 2002, passed a bond ordinance. Contracts have not been finalized on the remaining planned construction. These plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. This construction is not anticipated to be added to rate base. The Company's construction expenditures for 2001 were entirely funded through cash generated from operations. In the first quarter of 2002, the Company utilized its liquidity arrangements to cover the difference between the timing of its cash flows and its construction commitments. To meet its capital needs for its planned expansion of its generation capabilities, the Company expects that it will have to access the capital markets. Otherwise, the Company anticipates that internal cash generation and current debt capacity will be sufficient to meet all its other capital requirements for the years 2002 through 2006. 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, 2002, PNM had $190 million of available liquidity arrangements, consisting of $150 million from an unsecured revolving credit facility ("Credit Facility"), $20 million in local lines of credit and $20 million from a reciprocal borrowing agreement with the Holding Company. The Credit Facility will expire in March 2003. There were $106.3 million in borrowings as of May 1, 2002. In addition, the Holding Company has a $20 million reciprocal borrowing agreement with PNM and $25 million in local lines of credit. 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 and wholesale 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. PNM's credit outlook is considered positive by Moody's Investor Services ("Moody's") and Fitch Ratings ("Fitch") and stable by Standard and Poors ("S&P"). Previously, in connection with PNM's announcement of its agreement to acquire Western Resources' electric utility operations, S&P, Moody's and Fitch placed PNM's securities ratings on negative credit watch pending review of the transaction. As a result of events which led the Company to conclude the acquisition could not be accomplished, ultimately leading the Company to terminate the transaction in January 2002, S&P, Moody's and Fitch removed the Company from negative credit watch. The Company is committed to maintaining its investment grade. S&P currently rates PNM's senior unsecured notes ("SUNs") and its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its preferred stock "BB". Moody's rates PNM's SUNs and senior unsecured pollution control revenue bonds "Baa3"; and preferred stock "Ba1". The EIP senior secured debt is also rated "Ba1". Fitch rates PNM's SUNs and senior unsecured pollution control revenue bonds "BBB-," PNM's EIP lease obligation "BB+" and PNM's 39 preferred stock "BB-." Investors are 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. Long-term Obligations and Commitments The following table shows PNM's long-term debt and operating leases as of March 31, 2002. As of March 31, 2002, the Holding Company has no long-term obligations except those acquired through consolidation with PNM.
Payments Due ----------------------------------------------------------------------- (In thousands) Less than Contractual 1 year 2-3 years 4-5 years After 5 Obligations Total years ------------- ----------- ----------- ----------- ------------- Long-Term Debt.................. $953,898 $ - $ - $268,420 $685,478 Operating Leases................ 524,930 32,333 66,592 70,560 355,445 ------------- ----------- ----------- ----------- ------------- Total Contractual Cash Obligations.................. $1,478,828 $32,333 $66,592 $338,980 $1,040,923 ============= =========== =========== =========== =============
PNM leases interests in Units 1 and 2 of PVNGS, certain transmission facilities, office buildings and other equipment under operating leases. The lease expense for PVNGS is $66.3 million per year over base lease terms expiring in 2015 and 2016. In 1998, PNM established PVNGS Capital Trust ("Capital Trust") for the purpose of acquiring all the debt underlying the PVNGS leases. PNM consolidates Capital Trust in its consolidated financial statements. The purchase was funded with the proceeds from the issuance of $435 million of SUNs, which were loaned to Capital Trust. Capital Trust then acquired and now holds the debt component of the PVNGS leases. For legal and regulatory reasons, the PVNGS lease payment continues to be recorded and paid gross with the debt component of the payment returned to PNM via Capital Trust. As a result, the net cash outflows for the PVNGS lease payment were $12.4 million as of 2002. The table above reflects the net lease payment. PNM's other significant operating lease obligations include the Eastern Interconnect Project ("EIP"), a transmission line with annual lease payments of $7.3 million, and a power purchase agreement for the entire output of Delta Person Generating Station ("Delta"), a gas-fired generating plant in Albuquerque, New Mexico with imputed annual lease payments of $6.0 million. The Company's off-balance sheet obligations are limited to PNM's operating leases and certain financial instruments related to the purchase and sale of energy (see below). The present value of PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and the Delta PPA was $225 million as of December 31, 2001. PNM has entered various long-term power purchase agreements obligating it to make aggregate fixed payments of $30.3 million plus the cost of production and a return. These contracts expire December 2006 through July 2010. In addition, PNM is obligated to sell electricity for $158.1 million in fixed 40 payments plus the cost of production and a return. These contracts expire December 2003 through June 2010. PNM's trading portfolio as of March 31, 2002 included open contract positions to buy $63.0 million of electricity and to sell $31.2 million of electricity. In addition, PNM had open contract positions classified as normal sales of electricity under the derivative accounting rules of $16.3 million and normal purchases of electricity of $42.9 million. PNM has a coal supply contract for the needs of San Juan Generating Station ("SJGS") until 2017. The contract contemplates the delivery of approximately 103 million tons of coal during its remaining term. The pricing is based on the cost of extraction plus a margin. PNM contracts for the purchase of gas to serve its jurisdictional customers. These contracts are short-term in nature supplying the gas needs for the current heating season and the following off-season months. The price of gas is a pass-through, whereby the Company recovers 100% of its cost of gas. Contingent Provisions of Certain Obligations The Holding Company and PNM have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. The Holding Company and/or PNM could be required to provide security, immediately pay outstanding obligations or be prevented from drawing on unused capacity under certain credit agreements, if the contingent requirements were to be triggered. The most significant consequences resulting from these contingent requirements are detailed in the discussion below. PNM's master purchase agreement for the procurement of gas for its jurisdictional customers contains a contingent requirement that could require PNM to provide security for its gas purchase obligations if the seller were to reasonably believe that PNM was unable to fulfill its payment obligations under the agreement. The master agreement for the sale of electricity in the Western System Power Pool ("WSPP") contains a contingent requirement that could require PNM to provide security if its' debt were to fall below the investment grade rating. The WSPP agreement also contains a contingent requirement, commonly called a material adverse change ("MAC") provision, which could require PNM to provide security if a material adverse change in its financial condition or operations were to occur. PNM's committed Credit Facility contains a MAC provision which if triggered could prevent PNM from drawing on its unused capacity under the Credit Facility. In addition, the Credit Facility contains a contingent requirement that requires PNM to maintain a debt-to-capital ratio of less than 70%. If PNM's debt-to-capital ratio were to exceed 70%, PNM could be required to repay all borrowings under the Credit Facility, be prevented from drawing on the unused capacity under the Credit Facility, and be required to provide security for all outstanding letters of credit issued under the Credit Facility. At March 31, 2002, the Company had $8.5 million of letters of credit outstanding. If a contingent requirement were to be triggered under the Credit Facility resulting in an acceleration of the outstanding loans under the Credit Facility, a cross-default provision in the PVNGS leases could occur if the accelerated amount is not paid. If a cross-default provision is triggered, the lessors have the ability to accelerate their rights under the leases, including acceleration of all future lease payments. 41 Planned Financing Activities PNM has $268.4 million of long-term debt that matures in August 2005. All other long-term debt matures in 2016 or later. The Company could enter into other 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 PNM'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 PNM's financial instruments would ultimately limit the amount of SUNs PNM would issue. PNM currently has $182.0 million of tax-exempt bonds outstanding that are callable at a premium in December 2002 and August 2003. PNM intends to refinance these bonds assuming the interest rate of the refinancing does not exceed the current interest rate of the bonds and has hedged the entire planned refinancing. In order to take advantage of current low interest rates, PNM entered into two forward starting interest rate swaps in November and December 2001 and three additional contracts during the first quarter of 2002. PNM designated these swaps as cash flow hedges. The hedged risks associated with these instruments are the changes in cash flows related to general moves in interest rates expected for the refinancing. The swaps effectively cap the interest rate on the refinancing to 4.9% plus an adjustment for PNM's and the industry's credit rating. PNM's assessment of hedge effectiveness is based on changes in the hedge interest rates. The derivative accounting rules, as amended, provide 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 transactions affect earnings. Any hedge ineffectiveness is required to be presented in current earnings. There was no material hedge ineffectiveness in the three months ended March 31, 2002. A forward starting swap does not require any upfront premium and captures changes in the corporate credit component of an investment grade company's interest rate as well as the underlying Treasury benchmark. The five forward interest rate starting swaps have termination dates and notional amounts as follows: one with a termination date of September 17, 2002 for a notional amount of $46.0 million and four with a termination date of May 15, 2003 for a combined notional amount of $136.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transaction is cash settled on the mandatory unwind date (strike date), corresponding to the refinancing date of the underlying debt. The settlement will be capitalized as a cost of issuance and amortized over the life of the debt as a yield adjustment. 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 ability of the Company's subsidiaries to pay dividends. Currently, PNM is the Company's primary source of dividends. As part of the order approving the formation of the holding company, the PRC placed certain restrictions on the ability of PNM to pay dividends to its parent. 42 The PRC order imposed the following conditions regarding dividends paid by PNM to the holding company: PNM cannot pay dividends which cause its debt rating to go below investment grade; and PNM cannot pay dividends in any year, as determined on a rolling four quarter basis, in excess of net earnings without prior PRC approval. Additionally, PNM has various financial covenants which limit the transfer of assets, through dividends or other means. In addition, the ability of the Company to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, its financial circumstances and performance, the PRC's decisions in various regulatory cases currently pending and which may be docketed in the future, the effect of deregulating generation markets and market economic conditions generally. The ability to recover stranded costs in deregulation (as amended), conditions imposed on holding company formation, future growth plans and the related capital requirements and standard business considerations may also affect the Company's ability to pay dividends. Consistent with the PRC's holding company order, PNM paid dividends of $127.0 million to the Company on December 31, 2001. On March 4, 2002, the PNM Board of Directors declared an additional dividend of approximately $5.5 million, which was paid March 19, 2002. On February 19, 2002, the Company's Board of Directors approved a 10 percent increase in the common stock dividend. The increase raises the quarterly dividend to $0.22 per share, for an indicated annual dividend of $0.88 per share. The Company's Board of Directors approved a policy for future dividend increases in the range of 8 to 10 percent annually, targeting a payout of between 50 to 60 percent of regulated earnings. The Company believes that this target is consistent with the Company's expectation of future operating cash flows and the cash needs of its planned increase in generating capacity. Capital Structure The Company's capitalization, including current maturities of long-term debt, at March 31, 2002 and December 31, 2001 is shown below: March 31, December 31, 2002 2001 ------------- -------------- Common Equity......................... 51.3% 50.8% Preferred Stock....................... 0.6 0.6 Long-term Debt........................ 48.1 48.6 ------------- -------------- Total Capitalization*.............. 100.0% 100.0% ============= ============== *Total capitalization does not include as debt the present value of PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and the Delta PPA which was $225 million as of March 31, 2002 and $225 million as of December 31, 2001. 43 OTHER ISSUES FACING THE COMPANY 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 supply service and energy-related service assets from distribution and transmission service assets. 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 Company is unable to predict the form its further restructuring will take under the delayed implementation of customer choice. In addition, 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. The amendments to the Restructuring Act required that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of supply service and energy-related service assets from distribution and transmission service assets, by July 1, 2001. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented. On December 31, 2001, the Company implemented the holding company structure without corporate separation of supply service and energy-related services assets from distribution and transmission services assets. This structure provides for a holding company whose current holdings will be PNM, Avistar and other inactive unregulated subsidiaries. This was effected through the share exchange between PNM shareholders and the holding company, PNM Resources. Avistar and most of the inactive unregulated subsidiaries became wholly-owned subsidiaries of the holding company in January 2002. The transfer of certain corporate related assets to the holding company also occurred in January 2002. There are no current plans to provide the holding company with significant debt financing. The 2002 session of the New Mexico Legislature resulted in enactment of tax measures favorable to the construction of merchant generating plants and plants fueled by renewable resources. The new laws provide authority for all local governments in the state to issue industrial revenue bonds for merchant generating plants smaller than 300 MW. The bonds provide exemptions from property taxes. Also enacted into law was a 5% investment tax credit for merchant generating plants smaller than 300 MW; tax credits for qualified generators using renewable resources; and an exemption from gross receipts tax for the cost of certain wind generation equipment. There is a growing concern in New Mexico about the use of water for merchant power plants, due to the increased activity in building these plants in the state, which has an arid climate. The availability of sufficient water supplies to meet all the needs of the state, including growth, is a major issue. It is expected that the Legislature will appoint an interim committee to study the impact of power plants on the state's water and other natural resources, with a report to be issued for the 2003 session. In building the Afton and Lordsburg plants, which are much smaller than other merchant plants under construction or planned by other generating companies, the Company has secured sufficient water rights. 44 On April 25, 2002, by a vote of 88-11, the U.S. Senate passed amendments to HR 4, the "Energy Policy Act of 2002". The Senate version contains provisions directly applicable to the electric industry, many of which were not contained in the House version of HR 4. As adopted by the Senate, HR 4 contains provisions revising FERC authority over utility mergers; provides direction to the FERC regarding the use of market-based rates; provides for possible refunds dating from the date of a complaint rather than the current 60 day waiting period; provides for a reliability organization to establish standards subject to the FERC oversight; requires the FERC to establish an electronic information system about wholesales sales and transmission; extends FERC jurisdiction over large municipal utilities, cooperatives and power marketing agencies; requires access to transmission for intermittent generators that are exclusively solar or wind; repeals Public Utility Holding Company Act ("PUHCA"); provides for federal and state access to holding company records; conditionally repeals the Public Utility Regulatory Policy Act ("PURPA") if qualifying facilities have access to independent, day-ahead and real-time auction based markets; requires states to consider adopting standards for real time pricing, time of use metering and net metering; authorizes the Federal Trade Commission ("FTC") to establish consumer protection rules; establishes consumer advocates in the Department of Justice ("DOJ"); requires federal agencies to attempt to purchase a percentage of electricity from renewable sources, starting at 3% increasing to 7.5%; establishes renewable portfolio standard for investor owned utilities that increases to 10% by 2020; establishes a voluntary registry for reporting greenhouse gas emissions and emission reductions (which could become mandatory for reporting emissions within 5 years); reforms nuclear decommissioning tax provisions; provides tax relief for sale of transmission assets to an independent transmission company; extends protections against liability for nuclear accidents under Price-Anderson Act. The differences in the two versions of HR 4 will be the subject of conference committee discussions later this year. The Company is unable to predict what form energy legislation will take if agreement is reached between the House and the Senate, if energy legislation will be passed or if it will be signed by the President if passed. Included in the debate over energy legislation are drilling in the Arctic National Wildlife Refuge and automobile fuel efficiency requirements. The Company along with other Southwest transmission owners formed WestConnect RTO, LLC ("WestConnect") a for-profit transmission company and made a filing on October 16, 2001 with the FERC. WestConnect is the only remaining Regional Transmission Organization ("RTO") still proposing a transmission asset owning company form of governance. However, WestConnect allows for, but does not require a member to transfer its transmission assets. WestConnect is awaiting a FERC order on its formation. The FERC has initiated a separate Notice of Proposed Rulemaking that would require implementation of new Open Access Transmission Tariffs by RTOs and by public utilities that own, operate, or control interstate transmission facilities. The new tariffs would adopt provisions to implement new transmission services and a standardized wholesale market design. The new functions would be implemented by an independent entity, which could be an RTO, that would perform services under the standard market design under rules applicable to all transmission customers. The Company has made comments on the Standard Market Design Staff papers along with the other WestConnect companies and will continue to participate in the rulemaking process. The Company is also following FERC rulemakings on Standards of Conduct and Standardizing Generation Interconnection Agreements and Procedures. 45 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. These 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 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 Nuclear Regulatory Commission 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 seek 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 assets continue to be classified as regulatory assets, although the Company has discontinued the use of accounting for rate regulated activities. The amendments to the Restructuring Act provide the opportunity for amortization of coal mine decommissioning costs currently estimated at approximately $100 million. The Company intends to seek recovery of these costs in its next rate case filing and believes that the costs are fully recoverable. The Company believes that any remaining portion of the regulatory assets will be fully recovered in future rates, including through a non-bypassable wires charge. The Company believes that the Restructuring Act, as amended, if properly applied, provides an opportunity for recovery of a reasonable amount of stranded costs should such costs exist at the time of separation. 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. 46 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 from 2007 through 2012 by means of a separate wires charge. The PRC may extend this date by up to one year. The Company may seek to recover transition costs already incurred in future rate cases that may occur prior to open access. The Company is unable to predict the amount of transition costs it may incur. To date, the Company has capitalized $156.4 million of expenditures that meet the Restructuring Act's definition of transition 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 system changes and public and customer education and communications. These costs 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. Depending on the amount of non-recoverable transition costs, if any, the resulting charge to earnings may have a material effect on the future financial results and position of the Company. Nuclear Regulatory Commission 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. 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. The results of the 1998 triannual decommissioning cost study indicated that PNM's share of the PVNGS decommissioning costs excluding spent fuel disposal will be approximately $181 million (in 1998 dollars). 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 does not require 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. 47 MERCHANT PLANT FILING Senate Bill ("SB") 266, enacted by the 2001 session of the New Mexico legislature, allowed public utilities to "invest in, construct, acquire or operate" a generating plant not intended to provide retail electric service, free of certain otherwise applicable regulatory requirements contained in the Public Utility Act. By order entered on March 27, 2001, the PRC found that these provisions of SB 266 raised issues such as cost allocations for ratemaking, revenue allocations for off-system sales, how the Commission can ensure the utility will meet its duty to provide service when the utility invests in such generating plant, how that plant will be financed and how transactions between regulated services and merchant plants will be conducted. The Company has filed a pleading addressing these issues and testimony in response to interested parties' requests. The PRC established a schedule for the filing of staff and intervenor testimony and for the Company's rebuttal testimony, culminating in a hearing initially scheduled for June 10, 2002, although that procedural schedule was recently vacated and the hearing has not yet been rescheduled. In November 2001, the Company began settlement negotiations with the PRC's utility staff and intervenors related to these PRC proceedings in order to resolve a number of matters. In addition to the issues being examined in the Company's merchant plant filing, discussions have included the future framework for restructuring the electric industry in New Mexico under the Restructuring Act, and a future retail electric rate path. The negotiations include the potential implementation and effective date of rates that would replace those approved under the rate freeze stipulation that remains in effect until January 1, 2003. The Company is currently unable to predict the impact these proceedings may have on its plans to expand its generating capacity and other operations. 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 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 during the first half of the year. As a result of the supply imbalance, the wholesale power market in the Western United States became extremely volatile and, while providing many marketing opportunities, presented and continues to present significant risk to companies selling power into this marketplace. Moderate weather in California, as well as certain regulatory actions (see below), have caused a significant decline in the price of wholesale electricity in the Western United States wholesale power market. In addition, conservation measures and new generation have or are expected to put downward pressure on wholesale electricity prices. As a result of these trends, the Company expects its earnings from wholesale power trading operations to be significantly lower in the future than the levels seen during the first half of 2001. The power market in the Western United States has been the subject of widespread national attention. At the heart of the situation were flaws in the California deregulation legislation and a significant imbalance between electric supply and demand. These circumstances were aggravated by other factors such as increases in gas supply costs, weather conditions and transmission constraints. The FERC and the California Public Utilities Commission ("CPUC") have entered a 48 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 put significant downward pressure on wholesale prices. The Company cannot predict the ultimate outcome of these governmental initiatives and their long-term 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 reached over $1,000 per MWh mainly due to the electric power shortages in the West although current price levels are much depressed from this level. Two of California's major utilities, Southern California Edison Company ("SCE") and Pacific Gas and Electric Co. ("PG&E"), were unable to fully recover their wholesale power costs from their retail customers. As a result, both utilities experienced severe liquidity constraints. PG&E eventually sought bankruptcy protection. 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 these markets be capped at $150 per MWh unless the seller could demonstrate that its costs exceeded the cap. This price cap was effectively modified by FERC orders issued in March and April 2001 that directed certain power suppliers to provide refunds for overcharges calculated on the basis of a formula that sanctioned wholesale prices considerably in excess of the $150 per 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 markets. The plan reflected in the April 26 order replaced the $150 per MWh soft cap previously established and applied during periods of system emergency. Thereafter, on June 19, 2001, the FERC issued still another order that changed the previous orders and expanded the price mitigation approach of the April 26 order to all of the Western region. As a result of the price mitigation plan and other factors, such as moderate weather in California and lower gas prices, wholesale electric prices declined significantly by the end of the third quarter and remained low since then. The Company is unable to predict the impact the price mitigation plan will ultimately have on the wholesale market, but expects that if wholesale electric prices remain at current levels, future operating revenues from Generation and Trading will be significantly lower than in the first half of 2001. The June 19 order also directed a FERC administrative law judge to convene a settlement conference to address potential refunds owed by sellers into the California market. The settlement conference, in which the Company participated, was ultimately unsuccessful, but the administrative law judge called in his recommendation to the FERC for an evidentiary hearing to resolve the dispute, suggesting that refunds were due; however, the estimated refunds were significantly lower than demanded by California, and in most instances, were offset by the amounts due suppliers from the Cal PX and Cal ISO. California had demanded refunds of approximately $9 billion from power suppliers. On July 25, 2001, acting on the recommendation of the administrative law judge, the FERC ordered an expedited fact-finding hearing to evaluate refunds for spot market transactions in California. The FERC also ordered a preliminary hearing to determine whether refunds were due resulting from wholesale sales into the Pacific Northwest. The Pacific Northwest matter was heard by an administrative law judge whose recommended decision declined to order refunds resulting from 49 sales into the Pacific Northwest, but the FERC has not yet acted on this recommended decision. The hearing on potential California refund obligations has not yet been completed and a recommended decision is not anticipated until the second half of 2002. The Company is unable to predict the ultimate outcome of these FERC proceedings, or whether the Company will be directed to make any refunds as the result of a FERC order. The FERC has also, partially in response to the Enron bankruptcy filing and to allegations that Enron may have engaged in market manipulation of portions of the Western United States wholesale power market, initiated a market manipulation investigation. In connection with that investigation all FERC jurisdictional and non-jurisdictional sellers into western electric and gas markets have been required to submit data regarding short-term transactions in 2000-2001. The Company made its data submission on April 2, 2002. Subsequently, in the first week of May 2002, new Enron documents came to light that raised additional concerns about Enron's trading practices. In light of these new revelations, on May 8, 2002, the FERC issued an order in the pending investigation requiring sellers to respond to detailed questions about whether they have engaged in trading practices similar to those practiced by Enron. Responses are due to be filed by May 22, 2002. 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 Cal PX and ISO, defaulted on payments due the Cal PX for power purchased from the Cal PX in 2000. These defaults caused the Cal PX to seek bankruptcy protection. The Company has filed its proofs of claims in the Cal PX and PG&E bankruptcy proceedings. Total amounts due from the Cal PX or Cal ISO for power sold to them in 2000 and 2001 total approximately $7 million. The Company has provided allowances for the total amount due from the Cal PX and Cal ISO. Prior to its bankruptcy filing, the Cal PX undertook to charge back the 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 issued a ruling on these complaints eliminating the "charge-back" mechanism. Additionally, in March 2002, the California Attorney General filed a complaint at the FERC against numerous sellers regarding prices for sales into the Cal ISO and Cal PX and to the California Department of Water Resources ("Cal DWR"). The Company was among the sellers identified in this complaint and the Company filed its answer and motion to intervene on April 2, 2002. In its answer, the Company defended its pricing and challenged the theory of liability underlying the California Attorney General's complaint. As addressed below, the California Attorney General has also threatened litigation in state court in California based on similar allegations. With the demise of the Cal PX in February 2001, the 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 were financed by legislative appropriation, with the expectation that this funding would be replaced with the issuance of revenue bonds by the state. In the first quarter of 2001, the Company began to sell power to the Cal DWR. The Company has regularly monitored its credit risk with regard to its Cal DWR sales and believes its exposure is prudent. 50 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. In 2001, in response to the increased credit risk and market price volatility described above, the Company provided an additional allowance against revenue of $3.5 million for anticipated losses to reflect management's estimate of the increased market and credit risk in the wholesale power market and its impact on 2001 revenues. No additional reserves were made for the three months ended March 31, 2002. Based on information available at March 31, 2002, the Company believes the total allowance for anticipated losses, currently established at $12.0 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. Other related investigations have been commenced by other federal and state governmental bodies. The California Attorney General has filed several lawsuits in California state court against certain power marketers for alleged unfair trade practices involving alleged overcharges for electricity. By letter dated April 9, 2002, the California Attorney General notified the Company of his intent to file a complaint in California state court against the Company by the middle of April 2002 concerning the Company's alleged failure to file rates for wholesale electricity sold in California and for allegedly charging unjust and unreasonable rates in the California markets. For each alleged violation, the letter indicates an intent to seek penalties of $2,500 per violation. The letter invited the Company to contact the California Attorney General's office before the complaint is filed, and the Company has met with the California Attorney General's office to begin a dialogue. To date, suit has not been filed by the Attorney General and the Company cannot predict the ultimate outcome of this matter. Several class action lawsuits have been filed in California state courts against electric generators and marketers, alleging that the defendants violated the law by manipulating the market to grossly inflate electricity prices. Named defendants in these lawsuits include Duke Energy ("Duke") and related entities along with other named sellers into the California market and numerous other "unidentified defendants." These lawsuits have been consolidated for hearing in 51 state court in San Diego. On May 3, 2002, the Duke defendants in the foregoing state court litigation served on PNM a cross-claim. Duke also cross-claimed against many of the other sellers into California. Duke asked for declaratory relief and for indemnification for any damages that might ultimately be imposed on Duke. PNM's answer will (unless an extension of time is obtained) be due in early June, and PNM is in the process of reviewing the cross-complaint. PNM cannot predict the ultimate outcome of this matter. TERMINATION OF WESTERN RESOURCES TRANSACTION On November 9, 2000, PNM and Western Resources announced that both companies' Boards of Directors approved an agreement under which PNM would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing. In July 2001, the KCC issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for a $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger. Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001, in New York state court seeking declarations that the transaction could not be accomplished as designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. On November 19, 2001, Western Resources filed a complaint against the Company in New York state court alleging breach of contract and breach of implied covenant of good faith and fair dealing. Western Resources alleged that the Company brought about the KCC orders, failed to assist in efforts to reverse the KCC orders, refused to renegotiate within the terms of the agreement, interfered with Western Resources' efforts to satisfy the terms of the agreement, and effected an unauthorized de facto termination of the agreement by filing its complaint. Western Resources alleges damages in excess of $650 million. The Company believes that the complaint filed by Western Resources is without merit and intends to vigorously defend itself against the complaint. The Company also intends to vigorously pursue its own complaint. On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. 52 On February 5, 2002, the District Court for Shawnee County, Kansas, dismissed without prejudice Western Resources' petition for judicial review of the KCC's split-off orders. The Court ruled that by filing a new financial plan in compliance with the orders, Western Resources accepted certain portions of the orders thereby creating a situation where further administrative action became necessary. As a result, the Court concluded that the matter was not ripe for judicial review and remanded the case to the KCC. On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate order. On April 8, 2002, Western Resources filed with the Kansas Supreme Court a Petition for Review of the Court of Appeals decision. On May 2, 2002, the New York court issued an order denying Western Resources' motion for stay or dismissal of the Company's complaint. At the same time, the court granted the Company's motion to dismiss Western Resources' complaint, without prejudice. As a result, the Company has been determined to be the plaintiff in the litigation but Western Resources will be allowed, when it files its answer, to reassert its claims against the Company as affirmative defenses or counterclaims, if it so chooses. On May 10, 2002, the Company filed an Amended Complaint seeking unspecified damages from Western Resources for numerous breaches of contract related to the determination that the split-off required by the agreement was unlawful and required prior approval by the KCC. The Company also seeks unspecified damages for additional breaches of contract because: Western Resources failed to provide the Company with the opportunity to review and comment on information related to the transaction provided by Western Resources to third parties; Western Resources failed to obtain the Company's consent to amend existing employee compensation and benefits plans or create new ones; and Western Resources filed for approval of an alternative debt reduction plan that represents the abandonment of the split-off required by the agreement. In addition the Company seeks numerous declarations from the court, including that the Company was not obligated to perform because conditions regarding performance were not satisfied; the Company did not breach when it terminated the agreement; and the rate case order constitutes a material adverse effect under the terms of the agreement. The Company is currently unable to predict the outcome of its litigation with Western Resources. Effects of Certain Events on Future Revenues On October 1, 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 ("DOE") as contracting agent for Kirtland Air Force Base ("KAFB"). In 2001, FERC issued a "proposed" order directing the Company to provide transmission service, but left the terms of service to be negotiated by the parties and subject to final FERC review and determination. In January 2002, the parties submitted a settlement agreement resolving most of the issues relating to the rates, terms and conditions of service. The settlement agreement reserves the Company's rights to seek rehearing and judicial review of any final order and to present other legal claims. On April 12, 2002, the FERC approved the settlement, and on April 29, 2002, the FERC issued its Final Order directing the Company to provide the service. The Company is evaluating its legal options in relation to the final order. A related PRC proceeding has been stayed, pending the outcome of the FERC case. Should DOE on behalf of KAFB choose to use WAPA for purchase and transmission services instead of the current retail sale that the Company makes to DOE, the effect of the FERC's proposed order to provide transmission service, depends upon the Company's ability to sell the power to a different customer and the price that the Company would obtain if it makes such a sale. The Company believes that the impact will be immaterial based on the facts above. 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 53 is unclear at this time. The EPA has reached a settlement with one of the companies sued by the Justice Department. Discovery continues in the pending litigation. No complaint has been filed against the Company by the EPA, 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 not yet known what changes in EPA policy, if any, may occur in the NSR area as a result of the change in administration in Washington. The National Energy Policy released May 2001 by the National Energy Policy Development Group, called for a review of the pending NSR enforcement actions and that review continues by the EPA. 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. Threatened Citizen Suit Under the Clean Air Act By letter dated January 9, 2002, counsel for the Grand Canyon Trust and Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a so-called "citizen suit" under the Clean Air Act, alleging that the Company and co-owners of the SJGS violated the Clean Air Act, and the implementing federal and state regulations, at SJGS. The notice indicates that penalties and injunctive relief may be sought. Under the Clean Air Act, GCT must wait at least 60 days after affording the Company notice (i.e., until March 9, 2002) before filing a lawsuit. The allegations contained in GCT's notice of intent to sue fall into three categories. First, GCT contends that the plant has violated, and is currently in violation of, the federal NSPS at all four units at SJGS. Second, GCT argues that the plant has violated, and is currently in violation of, the federal PSD rules, as well as the corresponding provisions of the New Mexico Administrative Code, at all four units. Third, GCT alleges that the plant has "regularly violated" the 20% opacity limit contained in SJGS's operating permit and set forth in federal and state regulations at Units 1, 3 and 4. The Company is currently investigating the allegations contained in the notice of intent to sue. Based on its investigation to date, the Company firmly believes that the allegations are without merit. By letter to GCT's counsel dated February 22, 2002, the Company vigorously disputed the allegations and affirmed its compliance with the laws in question. The Company adheres to high environmental standards as evidenced by its International Standards Organization ratings. In that letter, the Company also stated that the GCT had failed to provide sufficient information to permit full examination of the allegations. If a lawsuit is filed by GCT, as threatened, the Company will respond on behalf of the co-owners and vigorously defend in the litigation. The Company is, however, unable to predict the ultimate outcome of the matter. 54 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. The Company's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. The Company also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau which issued its report on March 18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the Company by the injured persons along with several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur as a result of the Pipeline Safety Bureau's investigation. 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 Arizona Public Service Company ("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 and cannot estimate with any certainty the potential impact on the Company's operations. LANDOWNER ENVIRONMENTAL CLAIMS In March 2002, a lawsuit was filed by a landowner owning property in the vicinity of the San Juan Generating Station, Raymond G. Hunt, against the Company and the owner of the coal mine that supplies coal to the plant. The lawsuit has not, however, been served on the defendants pending the outcome of scheduled discussions between the parties. The complaint seeks $20 million in damages, plus pre-judgment interest and punitive damages, based on allegations related to the alleged discharge of pollutants into an arroyo near the plant, including damage to the plaintiff's livestock. A jury trial has been demanded. The Company is unable to predict the outcome of this matter. NEW AND PROPOSED ACCOUNTING STANDARDS Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the recognition of a liability for legal obligations associated with the retirement of a tangible long-lived asset that result from the acquisition, construction or 55 development and/or the normal operation of a long-lived asset. The asset retirement obligation is required to be recognized at its fair value when incurred. The cost of the asset retirement obligation is required to be capitalized by increasing the carrying amount of the related long-lived asset by the same amount as the liability. This cost must be expensed using a systematic and rational method over the related asset's useful life. SFAS 143 is effective for the Company beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and is unable to predict its impact on the Company's operating results and financial position at this time. Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the FASB issued SFAS 144. The statement retains the requirements of the previously issued pronouncement on asset impairment, Statement of Financial Accounting Standards No. 121 ("SFAS 121"); however the SFAS 144 removes goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position. 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 all forward-looking statements are based upon current expectations and are subject to risk and uncertainties. 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 the local and national economy, changes in supply and demand in the market for electric power, the outcome of litigation relating to the Company's terminated transaction with Western Resources, the performance of generating units and transmission system, the success of the Company's planned generation expansion and state and federal regulatory and legislative decisions and actions, including the wholesale electric power pricing mitigation plan ordered by FERC on June 18, 2001, rulings issued by the PRC 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 FERC and 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 and wholesale power markets in the West, could cause the Company's results or outcomes to differ materially from those indicated by such forward-looking statements in this filing. 56 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, changes in interest rates and, historically, 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 the Company's financial instruments is set forth in "Critical Accounting Policies" section of Management's Discussion of Results of Operations and Financial Condition and the Financial Instruments note in the Notes to the Consolidated Financial Statements and incorporated by reference. The following additional information is provided. Risk Management The Company controls the scope of its various forms of risk through a comprehensive set of policies and procedures and oversight by senior level management and the Board of Directors. The Company's Finance Committee of the Board of Directors sets the risk limit parameters. An internal risk management committee ("RMC"), comprised of corporate and business segment officers, oversees all of the activities, which include commodity price, credit, equity, interest rate and business risks. The RMC has oversight for the ongoing evaluation of the adequacy of the risk control organization and policies. The Company has a risk control organization, headed by the Director of Financial Risk Management ("Risk Manager"), which is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions, on an enterprise-wide basis. The RMC's responsibilities specifically include: establishment of a general policy regarding risk exposure levels and activities in each of the business units; recommendation of the types of instruments permitted for trading; authority to establish a general policy regarding counterparty exposure and limits; authorization and delegation of trading transaction limits for trading activities; review and approval of controls and procedures for the trading activities; review and approval of models and assumptions used to calculate mark-to-market and risk exposure; authority to approve and open brokerage and counterparty accounts for derivative trading; review for trading and risk activities; and quarterly reporting to the Finance Committee and the Board of Directors on these activities. The RMC also proposes Value at Risk ("VAR") limits to the Finance Committee. The Finance Committee ultimately sets the aggregate VAR limit. It is the responsibility of each business unit to create its own control and procedures policy for trading within the parameters established by the Finance Committee. The RMC reviews and approves these policies, which are created with the assistance of the Chief Accounting Officer, Director of Internal Audit and the Risk Manager. Each business units' policies address the following controls: authorized risk exposure limits; authorized trading instruments and markets; authorized traders; policies on segregation of duties; policies on marking to market; responsibilities for trade capture; confirmation procedures; responsibilities for reporting results; statement on the role of derivatives trading; and limits on individual transaction size (nominal value) for traders. 57 To the extent an open position exists, fluctuating commodity prices can impact financial results and financial position, either favorably or unfavorably. As a result, the Company cannot predict with precision the impact that its risk management decisions may have on its businesses, operating results or financial position. Commodity Risk Trading and marketing operations often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. These risks fall into three different categories: price and volume volatility, credit risk of trading counterparties and adequacy of the control environment for trading. The company routinely enters into forward contracts and options to hedge purchase and sale commitments, fuel requirements and to minimize the risk of market fluctuations on the Generation and Trading Operations. 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 assesses the risk of these derivatives using the VAR method, in order to maintain the Company's total exposure within management-prescribed limits. The Company utilizes the variance/covariance model of VAR, which is a probabilistic model that measures the risk of loss to earnings in market sensitive instruments. The variance/covariance model relies on statistical relationships to analyze how changes in different markets can affect a portfolio of instruments with different characteristics and market exposure. VAR models are relatively sophisticated; however, the quantitative risk information is limited by the parameters established in creating the model. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used. The VAR methodology employs the following critical parameters: volatility estimates, market values of open positions, appropriate market-oriented holding periods and seasonally adjusted correlation estimates. The Company uses a holding period of three days as the estimate of the length of time that will be needed to liquidate the positions. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. The confidence level established is 99%. For example, if VAR is calculated at $10 million, it is estimated at a 99% confidence level that if prices move against the Company's positions, the Company's pre-tax gain or loss in liquidating the portfolio would not exceed $10 million in the three days that it would take to liquidate the portfolio. The Company accounts for the sale of its electric generation in excess of its jurisdictional needs or the purchase of jurisdictional needs as non-trading. Non-jurisdictional purchases for resale and subsequent resales are accounted for as energy trading contracts. With respect to the Company's trading portfolio, the VAR was $3.2 million. The Company calculates a portfolio VAR which in addition to its trading portfolio includes all non-trading designated contracts, 58 its generation assets excluded from jurisdictional rates and any excess jurisdictional capacity. This excess is determined using average peak forecasts for the respective block of power in the forward market. The Company's portfolio VAR was $16.5 million at March 31, 2002. The Company's VAR is regularly monitored by the Company's RMC. The RMC has put in place procedures to ensure that increases in VAR are reviewed and, if deemed necessary, acted upon to reduce exposures. 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 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. 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 RMC. The Company provides for losses due to market and credit risk. The Company's credit risk with its largest counterparty as of March 31, 2002 was $4.3 million. The Company hedges certain portions of natural gas supply contracts in order to protect its jurisdictional customers from adverse price fluctuations in the natural gas market. The financial impact of all hedge gains and losses, including the related costs of the program, is recoverable through the Company's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by gains and losses generated by these instruments. Interest Rate Risk As of March 31, 2002, the Company has an investment portfolio of fixed-rate government obligations and corporate securities which was subject to the risk of loss associated with movements in market interest rates. For accounting purposes, the portfolio is classified as available-for-sale and is marked-to-market. As a result, unrealized losses resulting from interest rate increases are recorded as a component of comprehensive income. If interest rates were to rise, 50 basis points from their levels at March 31, 2002, the fair value of these instruments would decline by 0.6% or $0.9 million. In addition, because of this interest rate sensitivity, early or unplanned redemption of these investments in a period of increasing interest rates would subject the Company to risk of a realized loss of principal as the fair market value of these investments would be less than their carrying value. The Company employs investment managers to mitigate this risk. As part of its investing strategies, the Company has diversified its portfolio with investments of varying maturity, obligors and limits credit exposure to high investment grade quality investments. The Company has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. All of the Company's long-term debt is fixed-rate debt, and therefore, does not expose the Company's earnings to a risk of loss due to adverse changes in market interest rates. However, the fair value of these debts instruments would increase by approximately 4.5% or $45.4 million if interest rates were to decline by 50 basis points from their levels at March 31, 2002. As of March 31, 2002, the fair value of the Company's long-term debt was $1.0 billion as compared to a book-value of $954.0 million. In general, an increase in fair value would impact 59 earnings and cash flows if the Company were to re-acquire all or a portion of its debt instruments in the open market prior to their maturity. Certain issuances of the Company's debt have call dates in December 2002 and August 2003. To hedge against the risk of rising interest rates and their impact on the economies of calling the debt, the Company has entered into two forward starting swaps in 2001 and three additional contracts in 2002. These forward interest rate swaps effectively lock-in interest rates for the notional amount of the debt that is callable at a rate of approximately 4.9% plus an adjustment for the Company's and industry's credit rating. At March 31, 2002, the fair market value of these derivative financial instruments was approximately $4.7 million in the Company's favor. The Company contributed $6.1 million in 2001 to a trust established to fund decommissioning costs for PVNGS. In January 2002, the Company contributed $23.5 million for plan year 2001 to the trust for the Company's pension plan, and other post retirement benefits. The securities held by the trusts had an estimated fair value of $499.4 million as of March 31, 2002, of which approximately 28.9% were fixed-rate debt securities that subject the Company to risk of loss of fair value with movements in market interest rates. If rates were to increase by 50 basis points from their levels at March 31, 2002, the decrease in the fair value of the securities would be 3.2% or $4.5 million. The Company does not currently recover or return in jurisdictional rates losses or gains on these securities; therefore, the Company is at risk for shortfalls in its funding of its obligations due to investment losses. However, the Company does not believe that long-term market returns over the period of funding will be less than required for the Company to meet its obligations. Equity Market Risk As discussed above under Interest Rate Risk, the Company contributes to trusts established to fund its share of the decommissioning costs of PVNGS and other post retirement benefits. The trust holds certain equity securities as of March 31, 2002. These equity securities also expose the Company to losses in fair value. Approximately 56% of the securities held by the various trusts were equity securities as of March 31, 2002. Similar to the debt securities held for funding decommissioning and certain pension and other postretirement costs, the Company does not recover or return in jurisdictional rates losses or gains on these equity securities. In 2001, the Company implemented an enhanced cash management strategy using derivative instruments based on the Standard & Poors 100 and 500 indices. The strategy is designed to capitalize on high market volatility or benefit from market direction. An investment manager is utilized to execute the program. The program is carefully managed by the RMC and limited to a one-day VAR of $5 million and a loss limit of $7.5 million. Trades are closed-out before the end of a reporting period and typically within the same day of execution. Recently, the RMC recommended and the Finance Committee approved the use of derivatives based on the Nasdaq composite index. 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. 60 NAVAJO NATION ENVIRONMENTAL ISSUES Four Corners is located on the Navajo Reservation and is held under an easement granted by the federal government as well as a lease from the Navajo Nation. APS is the Four Corners operating agent and the Company owns a 13% ownership interest in Units 4 and 5 of Four Corners. 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 "Navajo Acts"). The Navajo Acts purport to give the Navajo Nation Environmental Protection Agency authority to promulgate regulations covering air quality, drinking water, and pesticide activities, including those that occur at Four Corners. The Four Corners participants dispute that purported authority, and by letter dated October 12, 1995, the Four Corners participants requested the United States Secretary of the Interior to resolve their dispute with the Navajo Nation regarding whether or not the Navajo Acts apply to operations of Four Corners. On October 17, 1995, the Four Corners participants filed a lawsuit in the District Court of the Navajo Nation, Window Rock District, seeking, among other things, a declaratory judgment that: o the lease and federal easement preclude the application of the Navajo Acts to the operations of Four Corners; and o the Navajo Nation and its agencies and courts lack adjudicatory jurisdiction to determine the enforceability of the Navajo Acts as applied to Four Corners. On October 18, 1995, the Navajo Nation and the Four Corners participants agreed to indefinitely stay these proceedings so that the parties may attempt to resolve the dispute without litigation. The Secretary and the Court have stayed these proceedings pursuant to a request by the parties. The Company cannot currently predict the outcome of this matter. In February 1998, the EPA issued regulations identifying those Clean Air Act provisions for which it is appropriate to treat Indian tribes in the same manner as states. The EPA has announced that it has not yet determined whether the Clean Air Act would supersede pre-existing binding agreements between the Navajo Nation and the Four Corners participants that could limit the Navajo Nation's environmental regulatory authority over Four Corners. The Company believes that the Clean Air Act does not supersede these pre-existing agreements. The Company cannot currently predict the outcome of this matter. On August 8, 2000, the EPA signed an Eligibility Determination for the Navajo Nation for Grants Under Section 105 of the Clean Air Act in which the EPA determined that the Navajo Nation was eligible to receive grants under the Clean Air Act. On September 8, 2001, after learning of the eligibility determination, APS, as Four Corners operating agent, filed a Petition for Review of the EPA's decision in the United States Court of Appeals for the Ninth Circuit in order to ensure that the EPA's August 2000 determination not be construed to constitute a determination of the Navajo Nation's authority to regulate Four Corners. APS v. United States Environmental Protection Agency, No. 01-71577. APS, the EPA and other parties have requested that the Court stay any further briefing while they negotiate a settlement. 61 In April 2000, the Navajo Tribal Council approved operating permit regulations under the Navajo Nation Air Pollution Prevention and Control Act. The Four Corners participants believe that the regulations fail to recognize that the Navajo Nation did not intend to assert jurisdiction over Four Corners. On July 12, 2000, the Four Corners participants each filed a petition with the Navajo Supreme Court for review of the operating permit regulations. The Company cannot currently predict the outcome of this matter. KAFB CONTRACT In 1999, the Company was informed 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 date that 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 October 1, 1999, WAPA filed a petition requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA on behalf of DOE and several other entities located on KAFB under the Company's Open Access Transmission Tariff. 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. WAPA requested rehearing of FERC's April 13, 2001 order. In a proposed order issued on June 13, 2001, FERC granted WAPA's request for rehearing. FERC determined that WAPA qualified for an exemption to the prohibition against an order requiring service to retail customers and that FERC therefore could require the Company to provide the requested service. FERC directed the Company and WAPA to engage in negotiations concerning rates, terms and conditions of service, including compensation. On January 18, 2002, the parties submitted a settlement agreement resolving most of the issues relating to the rates, terms and conditions of service. The partial settlement reserved one issue for FERC decision or further proceedings. The reserved issue relates to whether WAPA is entitled to a credit against payments for transmission service for certain facilities located near KAFB. The settlement agreement filed at FERC reserves the Company's rights to seek rehearing and judicial review of any final order and to present other legal claims. On April 12, 2002, the FERC approved the settlement. On April 29, 2002, the FERC issued its final order directing the Company to provide service. The Company is evaluating its legal options in relation to the final order. 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 and KAFB continues to purchase retail service pending resolution of all relevant issues. The PRC case has been held in abeyance, pending the outcome of the FERC proceeding. 62 AVISTAR SEVERANCE When the Company sold its water utility assets to the City of Santa Fe ("City") in 1995, the parties also entered into a Maintenance and Operations Agreement ("Agreement"), agreeing that the City would offer employment to the water utility employees when the Agreement expired. The Agreement was assigned to Avistar, Inc., and it expired in July 2001. The City assumed all maintenance and operations, and offered employment to the employees. Because the employees would continue performing the same jobs at the same location(s), the Company had previously excluded the non-union employees from eligibility for severance benefits under the Company's non-union severance plans. Similarly, the IBEW Local 611 had been on notice that the Company had negotiated for the continued employment of the IBEW-represented employees, making them ineligible for severance benefits under Article 24 of the Collective Bargaining Agreement ("CBA") between the Company and the IBEW. In July 2001, the Agreement ended, and most of the water operations employees accepted employment with the City. However, on March 27, 2001, the IBEW began an internal grievance claiming that about twenty-eight represented employees now employed by the City are nonetheless eligible for severance benefits under Article 24 of the CBA. The Company has denied their eligibility. The Company and Local 611 are scheduled to arbitrate the dispute in late May 2002. The Company is unable to predict the outcome of this matter. WESTERN RESOURCES On November 9, 2000, the Company and Western Resources announced that both companies' Boards of Directors approved an agreement under which the Company would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing. In July, 2001, the KCC issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger. Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001 in New York state court seeking declarations that the transaction could not be accomplished as designed 63 due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. On November 19, 2001, Western Resources filed a complaint against the Company in New York state court alleging breach of contract and breach of implied covenant of good faith and fair dealing. Western Resources alleged that the Company brought about the KCC orders, failed to assist in efforts to reverse the KCC orders, refused to renegotiate within the terms of the agreement, interfered with Western Resources' efforts to satisfy the terms of the agreement, and effected an unauthorized de facto termination of the agreement by filing its complaint. Western Resources alleges damages in excess of $650 million. The Company believes that the complaint filed by Western Resources is without merit and intends to vigorously defend itself against the complaint. The Company also intends to vigorously pursue its own complaint. On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. On February 5, 2002, the District Court for Shawnee County, Kansas, dismissed without prejudice Western Resources' appeal of the KCC's split-off orders. The Court ruled that, by filing a new financial plan in compliance with the orders, Western Resources accepted certain portions of the orders thereby creating a situation where further administrative action became necessary. As a result, the Court concluded that the matter was not ripe for judicial review and remanded the case to the KCC. On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate order. On April 8, 2002, Western Resources filed with the Kansas Supreme Court a Petition for Review of the Court of Appeals decision. On May 2, 2002, the New York court issued an order denying Western Resources' motion for stay or dismissal of the Company's complaint. At the same time, the court granted the Company's motion to dismiss Western Resources' complaint, without prejudice. As a result, the Company has been determined to be the plaintiff in the litigation but Western Resources will be allowed, when it files its answer, to reassert its claims against the Company as affirmative defenses or counterclaims, if it so chooses. On May 10, 2002, the Company filed an Amended Complaint seeking unspecified damages from Western Resources for numerous breaches of contract related to the determination that the split-off required by the agreement was unlawful and required prior approval by the KCC. The Company also seeks unspecified damages for additional breaches of contract because: Western Resources failed to provide the Company with the opportunity to review and comment on information related to the transaction provided by Western Resources to third parties; Western Resources failed to obtain the Company's consent to amend existing employee compensation and benefits plans or create new ones; and Western Resources filed for approval of an alternative debt reduction plan that represents the abandonment of the split-off required by the agreement. In addition the Company seeks numerous declarations from the court, including that the Company was not obligated to perform because conditions regarding performance were not satisfied; the Company did not breach when it terminated the agreement; and the rate case order constitutes a material adverse effect under the terms of the agreement. The Company is unable to predict the ultimate outcome of its litigation with Western Resources. 64 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits: 15.0 Letter Re: Unaudited Interim Financial Information b. Reports on Form 8-K: Report dated and filed April 5, 2002 reporting the Company expects lower prices will reduce 2002 earnings. Report dated and filed April 9, 2002 reporting the Company's Comparative Operating Statistics for the month of March 2002 and 2001 and the year ended March 31, 2002 and 2001. Report dated and filed April 19, 2002 reporting the Company's notice of annual meeting proxy statement relating to its annual shareholders meeting to be held on May 14, 2002. Report dated and filed April 24, 2002 reporting the Company's Quarter and Three Months Ended March 31, 2002 Earnings Announcement and Consolidated Statement of Earnings. Report dated and filed May 10, 2002 reporting the Company's Comparative Operating Statistics for the month of April 2002 and 2001 and the year ended April 30, 2002 and 2001. 65 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. PNM RESOURCES, INC. AND PUBLIC SERVICE COMPANY OF NEW MEXICO --------------------------------------------- (Registrants) Date: May 15, 2002 /s/ John R. Loyack --------------------------------------------- John R. Loyack Vice President, Corporate Controller and Chief Accounting Officer (Officer duly authorized to sign this report) 66 EX-15 3 exh15.txt EXHIBIT 15.0 Exhibit 15 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included in this Form 10-Q, into the Company's previously filed Registration Statement File No. 33-65418, Registration Statement File No. 333-03289, Registration Statement File No. 333-03303, Registration Statement File No. 333-10993, Registration Statement File No. 333-32170, Registration Statement File No. 333-53367, Registration Statement File No. 333-61598, Registration Statement No. 333-73648, Registration Statement No. 333-76288, and Registration Statement No. 333-76316. Albuquerque, New Mexico May 15, 2002 -----END PRIVACY-ENHANCED MESSAGE-----