10-Q 1 f10q_09302002.txt THIRD QUARTER 10-Q SEPTEMBER 30, 2002 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 SECURITIES EXCHANGE ACT OF 1934 For the period ended September 30, 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 Mexic 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 November 1, 2002 ---------- ----- ------------------------------- PNM Resources, Inc. Common Stock, 39,117,799 No Par Value PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO INDEX Page No. PART I. FINANCIAL INFORMATION: Reports of Independent Public Accountants............................... 3 ITEM 1. FINANCIAL STATEMENTS PNM Resources, Inc. and Subsidiaries Consolidated Statements of Earnings Three and Nine Months Ended September 30, 2002 and 2001...... 7 Consolidated Balance Sheets September 30, 2002 and December 31, 2001..................... 8 Consolidated Statements of Cash Flows Nine Months Ended September 30, 2002 and 2001................ 10 Consolidated Statements of Comprehensive Income Three and Nine Months Ended September 30, 2002 and 2001...... 11 Public Service Company of New Mexico Consolidated Statements of Earnings Three and Nine Months Ended September 30, 2002 and 2001...... 12 Consolidated Balance Sheets September 30, 2002 and December 31, 2001..................... 13 Consolidated Statements of Cash Flows Nine Months Ended September 30, 2002 and 2001................ 15 Consolidated Statements of Comprehensive Income Three and Nine Months Ended September 30, 2002 and 2001...... 16 Notes to Consolidated Financial Statements........................... 17 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............... 34 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK................................................. 79 ITEM 4. CONTROLS AND PROCEDURES........................................ 86 PART II. OTHER INFORMATION: ITEM 1. LEGAL PROCEEDINGS.............................................. 87 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................... 92 Signature.................................................................. 94 Certifications............................................................. 95 2 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of PNM Resources, Inc. Albuquerque, New Mexico We have reviewed the accompanying condensed consolidated balance sheet of PNM Resources, Inc. and subsidiaries (the Company) as of September 30, 2002, and the related condensed consolidated statements of earnings and comprehensive income for the three-month and nine-month periods ended September 30, 2002 and of cash flows for the nine-month period ended September 30, 2002. 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 of 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 of America, 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 such consolidated financial statements as of September 30, 2002, and for the three- and nine-month periods then ended for them to be in conformity with accounting principles generally accepted in the United States of America. The accompanying financial information as of December 31, 2001, and for the three- and nine-month periods ended September 30, 2001, were not audited or reviewed by us and, accordingly, we do not express an opinion or any other form of assurance on them. DELOITTE & TOUCHE LLP Omaha, Nebraska October 29, 2002 3 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Public Service Company of New Mexico Albuquerque, New Mexico We have reviewed the accompanying condensed consolidated balance sheet of Public Service Company of New Mexico (the Company) as of September 30, 2002, and the related condensed consolidated statements of earnings and comprehensive income for the three-month and nine-month periods ended September 30, 2002 and of cash flows for the nine-month period ended September 30, 2002. 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 of 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 of America, 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 such consolidated financial statements as of September 30, 2002, and for the three- and nine-month periods then ended for them to be in conformity with accounting principles generally accepted in the United States of America. The accompanying financial information as of December 31, 2001, and for the three- and nine-month periods ended September 30, 2001, were not audited or reviewed by us and, accordingly, we do not express an opinion or any other form of assurance on them. DELOITTE & TOUCHE LLP Omaha, Nebraska October 29, 2002 4 This is a copy of a report previously issued by Arthur Andersen LLP. The report has not been reissued by Arthur Andersen LLP nor has Arthur Andersen LLP provided an awareness letter for the inclusion of its report in this Quarterly Report on Form 10-Q. The report was issued prior to the formation of PNM Resources, Inc., the holding company of Public Service Company of New Mexico. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Public Service Company of New Mexico: We have reviewed the accompanying condensed consolidated balance sheet of PUBLIC SERVICE COMPANY OF NEW MEXICO (a New Mexico corporation) and subsidiaries as of September 30, 2001, and the related condensed consolidated statements of earnings and comprehensive income for the three-month and nine-month periods ended September 30, 2001 and 2000, and the condensed consolidated statements of cash flows for the nine-month periods ended September 30, 2001 and 2000. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures to financial data and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with auditing standards generally accepted in the United States, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the financial statements referred to above for them to be in conformity with accounting principles generally accepted in the United States. We have previously audited, in accordance with auditing standards generally accepted in the United States, the consolidated balance sheet and statement of capitalization of Public Service Company of New Mexico and subsidiaries as of December 31, 2000, and the related consolidated statements of earnings, and cash flows for the year then ended (not presented separately herein), and in our report dated January 26, 2001, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed consolidated balance sheet as of December 31, 2000 is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. ARTHUR ANDERSEN LLP Albuquerque, New Mexico November 13, 2001 5 This is a copy of a report previously issued by Arthur Andersen LLP. The report has not been reissued by Arthur Andersen LLP nor has Arthur Andersen LLP provided a consent to the inclusion of its report in this Quarterly Report on Form 10-Q. 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 audited the accompanying consolidated balance sheets and statements of capitalization of PNM Resources, Inc. (a New Mexico Corporation) and subsidiaries and Public Service Company of New Mexico and subsidiaries (a New Mexico Corporation) as of December 31, 2001 and 2000, and the related consolidated statements of earnings, cash flows and comprehensive income for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Companies' management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PNM Resources, Inc. and subsidiaries and Public Service Company of New Mexico and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Albuquerque, New Mexico February 1, 2002 6 ITEM 1. FINANCIAL STATEMENTS PNM RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------------- ------------------------------- 2002 2001 2002 2001 -------------- -------------- -------------- -------------- (In thousands, except per share amounts) Operating Revenues: Electric.................................. $252,861 $582,066 $677,340 $1,704,390 Gas....................................... 36,244 39,649 189,413 318,670 Unregulated businesses.................... 335 180 1,252 1,456 -------------- -------------- -------------- -------------- Total operating revenues................ 289,440 621,895 868,005 2,024,516 -------------- -------------- -------------- -------------- Operating Expenses: Cost of energy sold....................... 133,410 429,965 411,210 1,360,904 Administrative and general................ 38,041 39,241 106,494 117,494 Energy production costs................... 35,238 36,224 104,411 109,128 Depreciation and amortization............. 25,780 24,194 75,776 72,343 Transmission and distribution costs....... 15,949 18,402 47,937 48,760 Taxes, other than income taxes............ 7,077 6,380 24,589 21,436 Income taxes.............................. 4,810 20,067 16,317 89,182 -------------- -------------- -------------- -------------- Total operating expenses................ 260,305 574,473 786,734 1,819,247 -------------- -------------- -------------- -------------- Operating income........................ 29,135 47,422 81,271 205,269 -------------- -------------- -------------- -------------- Other Income and Deductions: Other income.............................. 12,194 12,766 35,200 39,995 Other deductions.......................... (5,235) (9,456) (6,182) (54,191) Income tax (expense) benefit.............. (2,541) (2,277) (10,815) 3,275 -------------- -------------- -------------- -------------- Net other income and deductions......... 4,418 1,033 18,203 (10,921) -------------- -------------- -------------- -------------- Earnings before interest charges........ 33,553 48,455 99,474 194,348 -------------- -------------- -------------- -------------- Interest Charges............................ 15,756 15,680 45,571 48,424 -------------- -------------- -------------- -------------- Net Earnings................................ 17,797 32,775 53,903 145,924 Preferred Stock Dividend Requirements....... 147 147 440 440 -------------- -------------- -------------- -------------- Net Earnings Applicable to Common Stock..... $ 17,650 $ 32,628 $ 53,463 $ 145,484 ============== ============== ============== ============== Net Earnings per Common Share: Basic..................................... $ 0.45 $ 0.83 $ 1.37 $ 3.72 ============== ============== ============== ============== Diluted................................... $ 0.45 $ 0.82 $ 1.35 $ 3.66 ============== ============== ============== ============== Dividends Paid per Share of Common Stock.... $ 0.22 $ 0.20 $ 0.64 $ 0.60 ============== ============== ============== ==============
The accompanying notes are an integral part of these condensed financial statements. 7 PNM RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31, 2002 2001 -------------- ------------- (Unaudited) (In thousands) ASSETS Utility Plant: Electric plant in service....................................... $2,201,768 $2,118,417 Gas plant in service............................................ 615,979 575,350 Common plant in service and plant held for future use........... 47,540 45,223 ------------- ------------- 2,865,287 2,738,990 Less accumulated depreciation and amortization.................. 1,310,747 1,234,629 ------------- ------------- 1,554,540 1,504,361 Construction work in progress................................... 228,390 249,656 Nuclear fuel, net of accumulated amortization of $19,327 and $16,954......................................... 29,942 26,940 ------------- ------------- Net utility plant............................................. 1,812,872 1,780,957 ------------- ------------- Other Property and Investments: Other investments............................................... 404,998 552,453 Non-utility property, net of accumulated depreciation of $1,708 and $1,580........................................... 1,571 1,784 ------------- ------------- Total other property and investments.......................... 406,569 554,237 ------------- ------------- Current Assets: Cash and cash equivalents....................................... 29,991 26,057 Accounts receivables, net of allowance for uncollectible accounts of $15,575 and $18,025............................. 118,264 147,787 Other receivables............................................... 38,644 52,158 Inventories..................................................... 36,613 36,483 Regulatory assets............................................... 120 10,473 Short-term investments.......................................... 109,469 45,111 Other current assets............................................ 25,906 31,428 ------------- ------------- Total current assets.......................................... 359,007 349,497 ------------- ------------- Deferred Charges: Regulatory assets............................................... 199,764 197,948 Prepaid retirement costs........................................ 39,628 18,273 Other deferred charges.......................................... 89,458 33,726 ------------- ------------- Total deferred charges........................................ 328,850 249,947 ------------- ------------- $2,907,298 $2,934,638 ============= =============
The accompanying notes are an integral part of these condensed financial statements. 8 PNM RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31, 2002 2001 -------------- -------------- (Unaudited) CAPITALIZATION AND LIABILITIES In thousands) Capitalization: Common stockholders' equity: Common stock................................................... $ 622,723 $ 625,632 Accumulated other comprehensive loss, net of tax............... (40,810) (28,996) Retained earnings.............................................. 451,640 415,388 -------------- -------------- Total common stockholders' equity........................... 1,033,553 1,012,024 Minority interest................................................. 11,538 11,652 Cumulative preferred stock without mandatory redemption requirements...................................... 12,800 12,800 Long-term debt.................................................... 953,926 953,884 -------------- -------------- Total capitalization........................................ 2,011,817 1,990,360 -------------- -------------- Current Liabilities: Short-term debt.................................................... 100,000 35,000 Accounts payable.................................................... 99,528 120,918 Accrued interest and taxes.......................................... 59,833 72,022 Other current liabilities........................................... 55,702 101,697 -------------- -------------- Total current liabilities................................... 315,063 329,637 -------------- -------------- Deferred Credits: Accumulated deferred income taxes................................... 111,670 120,153 Accumulated deferred investment tax credits......................... 42,366 44,714 Regulatory liabilities.............................................. 53,814 52,890 Regulatory liabilities related to accumulated deferred income tax... 14,163 14,163 Accrued postretirement benefit costs................................ 15,198 14,929 Other deferred credits.............................................. 343,207 367,792 -------------- -------------- Total deferred credits....................................... 580,418 614,641 -------------- -------------- $2,907,298 $2,934,638 ============== ==============
The accompanying notes are an integral part of these condensed financial statements. 9 PNM RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)
Nine Months Ended September 30, -------------------------- 2002 2001 ------------ ------------ (In thousands) Cash Flows From Operating Activities: Net earnings...................................................... $ 53,903 $ 145,924 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization................................. 85,625 80,086 Other, net.................................................... (25,276) 15,413 Changes in certain assets and liabilities: Accounts receivables........................................ 29,523 (19,497) Other assets................................................ 907 36,490 Accounts payable............................................ (21,390) (51,714) Accrued taxes............................................... (10,369) 80,907 Other liabilities........................................... (8,889) 9,251 ------------ ------------ Net cash flows provided by operating activities............. 104,034 296,860 ------------ ------------ Cash Flows From Investing Activities: Utility plant additions........................................... (166,640) (165,127) Redemption of short-term investments.............................. 45,000 - Return of principal of PVNGS lessor notes......................... 17,531 16,674 Other............................................................. (32,493) (5,440) ------------ ------------ Net cash flows used for investing activities................ (136,602) (153,893) ------------ ------------ Cash Flows From Financing Activities: Borrowings........................................................ 65,000 - Exercise of employee stock options................................ (2,909) (3,589) Dividends paid.................................................... (25,475) (23,905) Other............................................................. (114) (559) ------------ ------------ Net cash flows provided by (used for) financing activities.. 36,502 (28,053) ------------ ------------ Increase in Cash and Cash Equivalents............................... 3,934 114,914 Beginning of Period................................................. 26,057 107,691 ------------ ------------ End of Period....................................................... $ 29,991 $222,605 ============ ============ Supplemental Cash Flow Disclosures: Interest paid..................................................... $ 45,610 $ 48,298 ============ ============ Capitalized interest.............................................. $ 5,465 $ - ============ ============ Income taxes paid, net............................................ $ 43,534 $ 56,150 ============ ============
The accompanying notes are an integral part of these condensed financial statements. 10 PNM RESOURCES, INC. AND SUBSIDIARIES CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, -------------------------- --------------------------- 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (In thousands) Net Earnings......................................... $ 17,797 $32,775 $ 53,903 $145,924 ------------ ------------ ------------ ------------ Other Comprehensive Income (Loss), net of tax: Unrealized gain (loss) on securities: Unrealized holding gains (losses) arising during the period........................... 3,381 (1,459) 1,189 (885) Reclassification adjustment for (gains) losses included in net income....... (49) 341 (475) (693) 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.................. (12,963) (33,385) (13,303) (3,278) Reclassification adjustment for (gains) losses in net income................ (141) 15,455 775 (5,031) ------------ ------------ ------------ ------------ Total Other Comprehensive Loss....................... (9,772) (19,048) (11,814) (2,959) ------------ ------------ ------------ ------------ Total Comprehensive Income........................... $8,025 $ 13,727 $ 42,089 $142,965 ============ ============ ============ ============
The accompanying notes are an integral part of these condensed financial statements. 11 ITEM 1. FINANCIAL STATEMENTS PUBLIC SERVICE COMPANY OF NEW MEXICO CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, -------------------------- -------------------------- 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (In thousands) Operating Revenues: Electric..................................... $252,861 $582,066 $677,340 $1,704,390 Gas.......................................... 36,244 39,649 189,413 318,670 Unregulated businesses....................... - 180 - 1,456 ------------ ------------ ------------ ------------ Total operating revenues................... 289,105 621,895 866,753 2,024,516 ------------ ------------ ------------ ------------ Operating Expenses: Cost of energy sold.......................... 132,599 429,965 410,399 1,360,904 Administrative and general................... 40,768 39,241 104,510 117,494 Energy production costs...................... 35,238 36,224 104,411 109,128 Depreciation and amortization................ 25,541 24,194 75,294 72,343 Transmission and distribution costs.......... 15,949 18,402 47,937 48,760 Taxes, other than income taxes............... 7,529 6,380 23,610 21,436 Income taxes................................. 8,209 20,067 20,714 89,182 ------------ ------------ ------------ ------------ Total operating expenses................... 265,833 574,473 786,875 1,819,247 ------------ ------------ ------------ ------------ Operating income........................... 23,272 47,422 79,878 205,269 ------------ ------------ ------------ ------------ Other Income and Deductions: Other income................................. 9,656 12,766 29,149 39,995 Other deductions............................. (2,992) (9,456) (6,744) (54,191) Income tax (expense) benefit................. (1,986) (2,277) (8,870) 3,275 ------------ ------------ ------------ ------------ Net other income and deductions............ 4,678 1,033 13,535 (10,921) ------------ ------------ ------------ ------------ Earnings before interest charges........... 27,950 48,455 93,413 194,348 Interest Charges............................... 15,788 15,680 45,744 48,424 ------------ ------------ ------------ ------------ Net Earnings Before Preferred Stock Dividends 12,162 32,775 47,669 145,924 Preferred Stock Dividend Requirements.......... 147 147 440 440 ------------ ------------ ------------ ------------ Net Earnings................................... $ 12,015 $ 32,628 $ 47,229 $ 145,484 ============ ============ ============ ============
The accompanying notes are an integral part of these condensed financial statements. 12 PUBLIC SERVICE COMPANY OF NEW MEXICO CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31, 2002 2001 -------------- ------------- (Unaudited) (In thousands) ASSETS Utility Plant: Electric plant in service..................................... $2,201,768 $2,118,417 Gas plant in service.......................................... 615,979 575,350 Common plant in service and plant held for future use......... 18,661 45,223 -------------- ------------- 2,836,408 2,738,990 Less accumulated depreciation and amortization................ 1,306,896 1,234,629 -------------- ------------- 1,529,512 1,504,361 Construction work in progress................................. 220,314 249,656 Nuclear fuel, net of accumulated amortization of $19,327 and $16,954....................................... 29,942 26,940 -------------- ------------- Net utility plant........................................... 1,779,768 1,780,957 -------------- ------------- Other Property and Investments: Other investments............................................. 399,822 446,784 Non-utility property, net of accumulated depreciation of zero and $1,580........................................... 966 1,784 -------------- ------------- Total other property and investments........................ 400,788 448,568 -------------- ------------- Current Assets: Cash and cash equivalents..................................... 20,418 14,677 Accounts receivables, net of allowance for uncollectible accounts of $15,575 and $18,025........................... 118,264 147,787 Other receivables............................................. 37,716 52,158 Inventories................................................... 36,610 36,483 Regulatory assets............................................. 120 10,473 Short-term investments........................................ - 45,111 Other current assets.......................................... 16,150 21,477 -------------- ------------- Total current assets........................................ 229,278 328,166 -------------- ------------- Deferred Charges: Regulatory assets............................................. 199,736 187,475 Prepaid retirement costs...................................... 39,628 18,273 Other deferred charges........................................ 89,293 44,199 -------------- ------------- Total deferred charges...................................... 328,657 249,947 -------------- ------------- $2,738,491 $2,807,638 ============== =============
The accompanying notes are an integral part of these condensed financial statements. 13 PUBLIC SERVICE COMPANY OF NEW MEXICO CONDENSED CONSOLIDATED BALANCE SHEETS
September 30, December 31, 2002 2001 ------------- ------------- Unaudited) CAPITALIZATION AND LIABILITIES (In thousands) Capitalization: Common stockholder's equity: Common stock.................................................... $ 195,589 $ 195,589 Additional paid-in capital...................................... 430,043 430,043 Accumulated other comprehensive loss, net of tax................ (40,230) (28,996) Retained earnings............................................... 241,756 288,388 ------------- ------------- Total common stockholder's equity............................ 827,158 885,024 Minority interest.................................................. 11,538 11,652 Cumulative preferred stock without mandatory redemption requirements....................................... 12,800 12,800 Long-term debt..................................................... 953,926 953,884 ------------- ------------- Total capitalization......................................... 1,805,422 1,863,360 ------------- ------------- Current Liabilities: Short-term debt.................................................... 100,000 35,000 Intercompany debt.................................................. 21,319 - Accounts payable................................................... 91,606 120,918 Intercompany accounts payable...................................... 14,290 - Accrued interest and taxes......................................... 72,875 72,022 Other current liabilities.......................................... 56,392 101,697 ------------- ------------- Total current liabilities.................................... 356,482 329,637 ------------- ------------- Deferred Credits: Accumulated deferred income taxes.................................... 113,582 120,153 Accumulated deferred investment tax credits.......................... 42,366 44,714 Regulatory liabilities............................................... 53,814 52,890 Regulatory liabilities related to accumulated deferred income tax.... 14,163 14,163 Accrued postretirement benefit costs................................. 15,198 14,929 Other deferred credits............................................... 337,464 367,792 ------------- ------------- Total deferred credits............................................ 576,587 614,641 ------------- ------------- $2,738,491 $2,807,638 ============= =============
The accompanying notes are an integral part of these condensed financial statements. 14 PUBLIC SERVICE COMPANY OF NEW MEXICO CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended
September 30, --------------------------- 2002 2001 ------------ ------------ (In thousands) Cash Flows From Operating Activities: Net earnings........................................................ $ 47,669 $ 145,924 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization................................... 85,143 80,086 Other, net...................................................... (24,997) 15,413 Changes in certain assets and liabilities: Accounts receivables.......................................... 29,523 (19,497) Other assets.................................................. 3,573 36,490 Accounts payable.............................................. (29,312) (51,714) Accrued taxes................................................. 3,480 80,907 Other liabilities............................................. (44,179) 9,251 ------------ ------------ Net cash flows provided by operating activities............... 70,900 296,860 ------------ ------------ Cash Flows Used for Investing Activities: Utility plant additions............................................. (159,396) (165,127) Redemption of short-term investments................................ 45,000 - Return of principal of PVNGS lessor notes........................... 17,531 16,674 Other investing..................................................... (17,192) (5,440) ------------ ------------ Net cash flows used for investing activities.................. (114,057) (153,893) ------------ ------------ Cash Flows Used for Financing Activities: Borrowings.......................................................... 65,000 - Exercise of employee stock options.................................. - (3,589) Dividends paid...................................................... (51,597) (23,905) Other financing..................................................... (114) (559) Change in intercompany accounts..................................... 35,609 - ------------ ------------ Net cash flows provided by (used by) financing activities..... 48,898 (28,053) ------------ ------------ Increase in Cash and Cash Equivalents................................. 5,741 114,914 Beginning of Period................................................... 14,677 107,691 ------------ ------------ End of Period......................................................... $ 20,418 $222,605 ============ ============ Supplemental Cash Flow Disclosures: Interest paid....................................................... $ 45,776 $ 48,298 ============ ============ Capitalized interest................................................ $ 5,465 $ - ============ ============ Income taxes paid, net ............................................. $ 31,514 $ 56,150 ============ ============
The accompanying notes are an integral part of these condensed financial statements. 15 PUBLIC SERVICE COMPANY OF NEW MEXICO CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------- --------------------------- 2002 2001 2002 2001 ----------- ------------ ------------ ------------ (In thousands) Net Earnings......................................... $ 12,162 $ 32,775 $47,669 $145,924 ----------- ------------ ------------ ------------ Other Comprehensive Income (Loss), net of tax: Unrealized gain (loss) on securities: Unrealized holding gains (losses) arising during the period............................ 507 (1,459) 737 (885) Reclassification adjustment for (gains) losses included in net income....... (49) 341 (475) (693) 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.................. (11,932) (33,385) (12,271) (3,278) Reclassification adjustment for (gains) losses in cash flow hedges........... (141) 15,455 775 (5,031) ----------- ------------ ------------ ------------ Total Other Comprehensive Loss....................... (11,615) (19,048) (11,234) (2,959) ----------- ------------ ------------ ------------ Total Comprehensive Income........................... $ 547 $ 13,727 $36,435 $142,965 =========== ============ ============ ============
The accompanying notes are an integral part of these condensed financial statements. 16 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Company Overview PNM Resources, Inc. (the "Holding Company") is an investor-owned holding company of energy and energy related companies. Its principal subsidiary, Public Service Company of New Mexico ("PNM"), is an integrated public utility primarily engaged in the generation, transmission, distribution and sale and trading of electricity; the 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. Upon the completion on December 31, 2001, of a one-for-one share exchange between PNM and the Holding Company, the Holding Company became the parent company of PNM. Prior to the share exchange, the Holding Company had existed as a subsidiary of PNM. The new parent company began trading on the New York Stock Exchange under the PNM symbol beginning on December 31, 2001. (2) Accounting Policies and Responsibilities for Financial Statements In the opinion of management of the Holding Company and PNM, the accompanying interim consolidated financial statements present fairly the Companies' financial position at September 30, 2002 and December 31, 2001, the consolidated results of their operations for the three and nine months ended September 30, 2002 and 2001 and the consolidated statements of cash flows for the nine months ended September 30, 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 Companies' annual consolidated financial statements have been condensed or omitted, as permitted under the applicable SEC rules and regulations. Readers of these statements should refer to the Companies' audited consolidated financial statements and notes for the year ended December 31, 2001, which are included in the Companies' 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. (3) Presentation The Notes to Consolidated Financial Statements of PNM Resources, Inc. and Subsidiaries and PNM (collectively the "Company") are presented on a combined basis. The 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 of PNM were dividended to the Holding Company pursuant to an order from the New Mexico Public Regulation Commission ("PRC"). Readers of the Notes to Consolidated Financial Statements should assume that the information presented applies to the consolidated results of operations and financial position of both PNM Resources, Inc. and Subsidiaries and PNM, except where the context or references clearly indicate otherwise. Discussions regarding specific contractual obligations generally reference the company that is legally obligated. 17 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) In the case of contractual obligations of PNM, these obligations are consolidated with PNM Resources, Inc. and Subsidiaries under generally accepted accounting principles ("GAAP"). Broader operational discussion refers to the Company. (4) Segment Information As it currently operates, 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 due to its immateriality and is combined with the distribution business line for disclosure purposes. UTILITY OPERATIONS Electric PNM provides retail electric service, regulated by the PRC, to a large area of north central New Mexico, including the cities of Albuquerque and Santa Fe, and certain other areas of New Mexico. PNM 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 Generation and Trading. Intersegment purchases from Generation and Trading 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 delivery and production that includes certain generation assets that are part of Generation and Trading plus a rate of return. Gas PNM's gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe. PNM's customer base includes both sales-service customers and transportation-service customers. Customer rates for gas service are set by the PRC based on the recovery of the cost of delivering gas plus a rate of return, with the cost of gas procured for customers being passed through to customers through a purchased gas adjustment clause ("PGAC"). In the first quarter of 2001, Generation and Trading procured its gas fuel supply from Gas. Beginning with the second quarter of 2001, Generation and Trading began procuring its gas supply independently of Gas and contracted with Gas for transportation services only. 18 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) GENERATION AND TRADING OPERATIONS Generation and Trading serves four principal markets. These include sales to PNM's Utility Operations to cover retail electric demand, sales to firm-requirement 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, PNM purchases power in the open market. As of September 30, 2002, the total net generation capacity of facilities owned or leased by PNM was 1,733 MW, including a 132 MW power purchase contract accounted for as an operating lease. UNREGULATED The Holding 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 Holding 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 union employees; fluctuations in fuel, purchased power and gas prices; the actions of utility regulatory commissions; changes in law and environmental regulations; the performance of PNM's generating units and the success of any generation expansion and external factors such as the weather. In the early 1990s, federal and state policymakers began investigating and implementing major reforms regarding the public utility industry, designed to transform electric generation into a competitive business separate from the regulated monopoly businesses of transmission and distribution, at least on a functional basis. These reforms introduced new risks into the Company's business which had the potential to impact future results, such as the Company's 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. However, as a result of the energy crisis in California, plans for restructuring the industry are undergoing fundamental review. The 2003 session of the New Mexico Legislature will review the introduction of bills to repeal existing legislation providing for customer choice and competition in retail electric power supplies, currently scheduled to commence in 2007. Any reforms that may be made to existing plans for restructuring the industry will also affect the Company's future results. In addition to the fate of retail electric competition in New Mexico, the Company's future results will continue to be affected on the wholesale side by the market price of electricity and natural gas costs, and the results of federal reforms regarding the wholesale market and transmission service. 19 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Summarized financial information by business segment for the three months ended September 30, 2002 and 2001 is as follows:
Utility ---------------------------------- Generation Electric Gas Total and Trading Unregulated Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 2002: Operating revenues: External customers............. $156,363 $36,244 $192,607 $ 96,497 $ 336 $ 289,440 Intersegment revenues.......... 177 666 843 96,592 (97,435) - Depreciation and amortization..... 8,338 5,160 13,498 11,107 1,175 25,780 Interest income................... 40 - 40 1,544 10,872 12,456 Interest charges.................. 6,060 3,494 9,554 4,657 1,545 15,756 Operating income (loss)........... 18,095 (946) 17,149 11,232 754 29,135 Income tax expense (benefit) from continuing operations...... 7,760 (2,976) 4,784 4,071 (1,504) 7,351 Segment net income (loss)......... 11,841 (4,539) 7,302 6,242 4,253 17,797 Total assets...................... 787,759 441,370 1,229,129 1,445,787 232,382 2,907,298 Gross property additions (deletions).................... 11,422 33,746 45,168 (10,850) 4,541 38,859 2001: Operating revenues: External customers............. $153,535 $39,649 $193,184 $428,531 $ 180 $ 621,895 Intersegment revenues.......... 177 - 177 95,413 (95,590) - Depreciation and amortization..... 8,219 5,400 13,619 10,565 10 24,194 Interest income................... 555 127 682 9,841 1,585 12,108 Interest charges.................. 5,611 2,423 8,034 4,471 3,175 15,680 Operating income (loss)........... 17,235 (138) 17,097 32,217 (1,892) 47,422 Income tax expense (benefit) from continuing operations...... 7,486 (1,914) 5,572 21,122 (4,350) 22,344 Segment net income (loss)......... 11,423 (2,923) 8,500 32,229 (7,954) 32,775 Total assets...................... 799,607 466,550 1,266,157 1,522,354 234,045 3,022,556 Gross property additions.......... 18,577 11,378 29,955 14,856 4,375 49,186
20 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Summarized financial information by business segment for the nine months ended September 30, 2002 and 2001 is as follows:
Utility --------------------------------- Generation Electric Gas Total and Trading Unregulated Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 2002: Operating revenues: External customers............. $431,929 $189,413 $621,342 $245,411 $ 1,252 $ 868,005 Intersegment revenues.......... 530 1,136 1,666 264,554 (266,220) - Depreciation and amortization..... 25,239 15,548 40,787 32,587 2,402 75,776 Interest income................... 395 21 416 2,339 31,203 33,958 Interest charges.................. 17,632 10,128 27,760 11,528 6,283 45,571 Operating income.................. 46,842 10,931 57,773 21,650 1,848 81,271 Income tax expense from continuing operations...... 18,958 1,342 20,300 6,355 477 27,132 Segment net income................ 28,930 2,048 30,978 9,698 13,227 53,903 Total assets...................... 787,759 441,370 1,229,129 1,445,787 232,382 2,907,298 Gross property additions.......... 37,888 51,324 89,212 69,581 7,847 166,640 2001: Operating revenues: External customers............. $424,249 $318,670 $742,919 $1,280,141 $ 1,456 $2,024,516 Intersegment revenues.......... 530 - 530 259,726 (260,256) - Depreciation and amortization..... 24,310 16,023 40,333 31,981 29 72,343 Interest income................... 1,555 677 2,232 29,546 5,467 37,245 Interest charges.................. 14,163 8,365 22,528 22,661 3,235 48,424 Operating income (loss)........... 45,275 12,665 57,940 149,017 (1,688) 205,269 Income tax expense (benefit) from continuing operations...... 19,564 2,775 22,339 86,682 (23,114) 85,907 Segment net income (loss)......... 29,854 4,234 34,088 132,273 (20,437) 145,924 Total assets...................... 799,607 466,550 1,266,157 1,522,354 234,045 3,022,556 Gross property additions.......... 47,082 28,836 75,918 78,674 10,535 165,127
(5) 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. 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 September 30, 2002 was $3.9 million. 21 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Natural Gas Contracts Pursuant to a 1997 order issued by the New Mexico Public Utility Commission ("NMPUC"), predecessor to the PRC, PNM has 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 PGAC. 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 the risk of price fluctuation during the 2002-2003 heating season. PNM expended $6.0 million to purchase options that limit the maximum amount PNM will pay for gas during the winter heating season. PNM is recovering 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 nine months ended September 30, 2002, Generation and Trading settled forward trading contracts for the sale of electricity that generated $31.3 million of electric revenues by delivering 812,645 MWh. The Company purchased $55.4 million or 966,420 MWh of electricity under forward trading contracts to support these contractual sales and other open market sales opportunities. For the nine months ended September 30, 2001, Generation and Trading settled forward trading contracts for the sale of electricity that generated $70.7 million of electric revenues by delivering 320,000 MWh. The Company purchased $69.5 million or 300,000 MWh of electricity under forward trading contracts to support these contractual sales and other open market sales opportunities. As of September 30, 2002, PNM had open trading contract positions to buy $38.3 million and to sell $29.6 million of electricity. At September 30, 2002, PNM had a gross mark-to-market gain (asset position) on these trading contracts of $4.6 million and gross mark-to-market loss (liability position) of $12.9 million, with a net mark-to-market loss (liability position) of $8.3 million. The change in mark-to-market valuation recognized in earnings was a $22.1 million gain and a $26.8 million loss for the nine months ended September 30, 2002 and 2001, respectively. In addition, Generation and Trading entered into forward physical contracts for the sale of PNM's electric capacity in excess of its retail and wholesale firm requirement needs, including reserves, or the purchase of retail and wholesale firm requirements needs, including reserves, when resource shortfalls exist. The Company generally accounts for these derivative financial instruments as normal sales and purchases as defined by Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities", as amended ("SFAS 133"). PNM from time to time makes forward purchases to serve its retail needs when the cost of purchased power is less than the incremental cost of its generation. At September 30, 2002, PNM had open forward positions classified as normal sales of electricity of $36.1 million and normal purchases of electricity of $70.6 million. 22 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Generation and Trading, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby PNM's aggregate net open position is covered by its own excess generation capabilities. PNM is exposed to market risk if its generation capabilities were disrupted or if its retail load requirements were greater than anticipated. If PNM 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 that 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 the current low interest rates, PNM entered into five forward starting interest rate swaps in the fourth quarter of 2001 and 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 at 4.95% 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. For the nine months ended September 30, 2002, PNM recognized $0.4 million of hedge ineffectiveness in earnings. At September 30, 2002, the fair market value of these derivative financial instruments was approximately $20.3 million unfavorable to the Company. 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 benchmark. The five forward starting interest rate swaps have a termination date of May 15, 2003 for a combined notional amount of $182.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transaction 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. 23 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) (6) 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 September 30 (in thousands, except per share amounts):
Three Months Ended Nine Months Ended September 30, September 30, ------------------------- ------------------------- 2002 2001 2002 2001 ------------ ----------- ----------- ------------ Basic: Net Earnings.......................................... $ 17,797 $32,775 $53,903 $ 145,924 Preferred Stock Dividend Requirements................. 147 147 440 440 ------------ ----------- ----------- ------------ Net Earnings Applicable to Common Stock............... $ 17,650 $32,628 $53,463 $ 145,484 ============ =========== =========== ============ Average Number of Common Shares Outstanding........... 39,118 39,118 39,118 39,118 ============ =========== =========== ============ Net Earnings per Common Share (Basic)................. $ 0.45 $ 0.83 $ 1.37 $ 3.72 ============ =========== =========== ============ Diluted: Net Earnings Applicable to Common Stock Used in Basic Calculation........................... $17,650 $32,628 $53,463 $ 145,484 ============ =========== =========== ============ Average Number of Common Shares Outstanding........... 39,118 39,118 39,118 39,118 Diluted Effect of Common Stock Equivalents (a)........ 207 630 366 653 ------------ ----------- ----------- ------------ Average Common and Common Equivalent Shares Outstanding......................................... 39,325 39,748 39,484 39,771 ============ =========== =========== ============ Net Earnings per Share of Common Stock (Diluted)...... $ 0.45 $ 0.82 $ 1.35 $ 3.66 ============ =========== =========== ============
(a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of 1,881,588 and 718,745 for the three and nine months ended September 30, 2002, respectively. There were no anti-dilutive common stock equivalents in 2001. (7) 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 over the next five years depending on market conditions. PNM has expended $208.8 million as of September 30, 2002, of which $131.5 million was for equipment purchases. In November 2001, PNM broke ground to build Afton Generating Station ("Afton"), a 135 MW simple 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 southwestern New Mexico. On June 27, 2002, Lordsburg became fully operational and will serve the wholesale power market. 24 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) 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. These plants were not built to serve New Mexico retail customers and therefore will not be included in the rate base. However, it is possible that these plants may be needed in the future to serve the growing retail load. If so, these plants will have to be certified by the PRC and would then be included in the rate base. Terrorism Insurance As of October 1, 2002, the Company's non-nuclear property insurance contains a limitation on damage caused by terrorism. Terrorism coverage is subject to specific coverage provisions and the amount recoverable is limited to $5.0 million. Terrorism coverage for nuclear property and the Company's excess liability insurance has also changed. The nuclear property and excess liability changes are not considered material. PVNGS Liability and Insurance Matters The PVNGS participants have financial protection 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, PNM 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 PNM's 10.2% interest in the three PVNGS units, PNM'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 the payment of public liability claims in case of a catastrophic accident involving a nuclear power plant, were up for renewal in August 2002. While existing nuclear power plants 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. The U.S. House of Representatives (the "House") passed a renewal bill 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 U.S. Senate (the "Senate") approved a Price-Anderson Act amendment as a part of the comprehensive energy bill ("S.517"). House and Senate negotiators reached a compromise September 12, 2002. Price-Anderson Act reauthorization is now part of a comprehensive energy bill ("H.R.4"). Both the current law and the versions approved by the House and Senate provide for the primary financial protection limit to be the maximum amount available from private insurance sources. Those sources are currently being evaluated as to whether the $200 million now available for liability claims per reactor could be increased to keep pace with inflation. The terms in 25 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) H.R.4 for the Price-Anderson Act amendment would reauthorize for 15 years, increase the maximum assessment per reactor to approximately $99 million and change the annual limit from $10 million to $15 million. The retroactive assessments would be indexed to inflation. H.R.4 will not become law until the balance of the bill is finalized by the conferees, approved by both the House and Senate, and signed by the President. The Company cannot predict whether or not the U.S. Congress will renew the Price-Anderson Act or whether or not an increase will be made to the primary financial protection layer. In the event the comprehensive energy bill does not pass, it is possible that the Price-Anderson Act amendment would be passed as a stand-alone bill. However, 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 damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion as of October 1, 2002, a substantial portion of which must be applied to stabilization and decontamination. PNM 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. PNM is a member of an industry mutual insurer. This mutual insurer provides both the "all-risk" and increased cost of generation insurance to PNM. In the event of adverse losses experienced by this insurer, PNM is subject to an assessment. PNM's maximum share of any assessment is approximately $5.1 million per year. PVNGS Decommissioning Funding PNM 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 2001 decommissioning cost study indicated that PNM's share of the PVNGS decommissioning costs, excluding spent fuel disposal, would be approximately $201 million (2001 dollars). The estimated market value of the trusts at the end of September 30, 2002 was approximately $51.2 million. PNM did not provide any additional funding for the nine months ended September 30, 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, the DOE was to develop the facilities necessary for the storage and disposal of spent nuclear fuel and to have the first facility in operation by 1998. DOE has announced that such a repository now cannot be completed before 2010. 26 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 until Fall 2003. The operator of PVNGS believes it could augment that storage with the new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2003, subject to obtaining any required governmental approvals. PNM currently estimates that it will incur approximately $41.0 million (in 2001 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 that 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 2003. 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 PNM line near the location. The explosion destroyed a small building and injured two persons who were working in the building. PNM's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. PNM also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau (the "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 PNM by the injured persons along with several claims for property and business interruption damages have been resolved. The Company believes that the final 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 Westar Energy, Inc. (formerly known as Western Resources) ("Westar Energy") announced that both companies' boards of directors approved an agreement under which the Company would acquire the Westar Energy electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Westar Energy split-off its non-utility businesses to its shareholders prior to closing. After adverse rulings by the Kansas Corporation Commission regarding the proposed split-off pursuant to the agreement and regarding Westar Energy's electric rates, the transaction was terminated. The Company sued Westar Energy in New York state court for unspecified damages for breach of contract and for declaratory judgment. Westar Energy countersued, claiming entitlement to termination fees in the amount of $25 million, plus costs and fees, and other unspecified damages. 27 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) On September 25, 2002, the Company and Westar Energy jointly announced that they had settled the litigation, with each party dismissing its claims against the other party and each party bearing its own costs. Other There are various claims and lawsuits pending against the Company. 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 its 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. (8) 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 such reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). The Company's recorded minimum liability estimated to remediate its identified sites is $8.5 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. 28 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) For the nine months ended September 30, 2002 and 2001, the Company spent $0.7 million and $2.2 million, respectively, for remediation. The majority of the September 30, 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. (9) Company Realignment On August 22, 2002, the Company was realigned due to the changes in the gas and electric industry and particularly, the negative impact on the Company's earnings and growth prospects from wholesale market uncertainty. The changes included consolidation of similar functions. A total of 85 salaried and hourly employees were notified of their termination as part of the realignment. In accordance with EITF 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity", the Company incurred a liability of $8.8 million for severance and other related costs associated with the involuntary termination of employees, which was charged to operations in the quarter ended September 30, 2002. (10) 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 results from the acquisition, construction or development or the normal operation of a long-lived asset. The asset retirement obligation must be recognized at its fair value when incurred. The cost of the asset retirement obligation will 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 financial condition or results of operations 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 financial condition or results of operations. 29 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"). In April 2002, the FASB issued SFAS 145. This statement updates and clarifies existing accounting pronouncements for treatment of gains and losses from extinguishment of debt and eliminates an inconsistency between required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have similar economic effects as sale-leaseback transactions. In accordance with previous accounting standards, gains and losses from extinguishment of debt were classified as extraordinary gains and losses. The current statement permits gains and losses from extinguishment of debt to be classified as ordinary and included in income from operations, unless they are unusual in nature or occur infrequently and are therefore classified as an extraordinary item. Emerging Issues Task Force ("EITF") Issue 02-3 "Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities", EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and Statement of Financial Accounting Standards No. 133 ("SFAS 133") "Accounting for Derivative Instruments and Hedging Activities". The Company evaluates its energy contracts to determine if they meet the definition of a derivative and are therefore subject to the accounting requirements of SFAS 133. If an energy contract is determined not to be a derivative under SFAS 133, it is then evaluated under EITF 98-10 to determine whether it meets the definition of a trading activity and should be marked to market with gains and losses recognized in earnings and separately disclosed in the financial statements. EITF 98-10 allowed a gross or net presentation of these gains and losses in the statement of earnings. In June 2002, the EITF reached a consensus in EITF 02-3 that all energy trading activities must be presented on a net margin basis rather than a gross basis in the statement of earnings and further required that all prior periods be reclassified to conform to the current period presentation. On October 25, 2002, the EITF reached a consensus to rescind EITF 98-10 and will no longer allow energy contracts that do not meet the definition of a derivative under SFAS 133 to be marked to market and recognized in current earnings. As a result, all contracts which were marked to market under EITF 98-10 and must now be accounted for under the accrual method will be written back to cost with any difference included as a cumulative effect adjustment in the period of adoption. This transition provision will be effective for the first quarter of 2003. The disclosure provisions previously agreed to in EITF 02-3 have also been rescinded. In addition, any contracts within Statement 133 that are trading or held for trading and are settled physically should be reported on a net basis. Any contracts within Statement 133 that are not considered trading and are settled physically should be reported on a gross basis. The EITF has directed the FASB staff to provide a definition of trading activities to be included in the final written consensus of EITF 02-3. The decision to rescind EITF 98-10, the uncertainty as to the ultimate definition of trading activities and the October 2002 consensus as to the effective date for adoption of EITF 02-3 has nullified the June 2002 consensus on net margin versus gross basis presentation. Therefore, the Company has not reclassified its energy trading activities to a net margin presentation as of September 30, 2002 and is currently assessing the impact of the EITF's October consensus on the accounting for its energy contract portfolio. The Company expects to adopt EITF 02-3 in its entirety in the first quarter of 2003. 30 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) The SEC has indicated that financial statement reclassifications related to periods previously audited by Arthur Andersen LLP ("Arthur Andersen") may require the successor auditor to audit the prior periods and issue a new audit report. Arthur Andersen audited the Company's financial statements for the fiscal years 2001 and 2000. The successor auditor, Deloitte and Touche, has not issued a new review report for the three and nine months ended September 30, 2001. However, Deloitte and Touche will perform an audit of the Companies' financial statements for fiscal year 2001. (11) Subsequent Events New Long-Term Power Contract On October 21, 2002, PNM entered into an agreement with FPL Energy LLC ("FPL"), a subsidiary of FPL Group, Inc., to develop a 200 MW wind generation facility in New Mexico. FPL Energy will build, own and operate the New Mexico Wind Energy Center ("NMWE"), consisting of 136 wind-powered turbines on a site in eastern New Mexico. PNM will buy all the power generated by the NMWE under a 25-year contract. Construction of the wind energy site is expected to begin later this year. Construction on a facility of this size typically takes six to nine months to complete. PNM will ask the PRC to approve a voluntary tariff that will allow PNM retail customers to buy wind-generated electricity for a small monthly premium. Power from the facility not subscribed by PNM jurisdictional customers under the voluntary program will be sold on the wholesale market, either within New Mexico or outside of the state. Electric Rate Agreement In November 2001, PNM began settlement negotiations with the PRC utility staff and intervenors in order to resolve its merchant plant filing and other matters. Discussions included the future framework for restructuring the electric industry in New Mexico under the Restructuring Act, a future retail electric rate path and PNM's merchant plant filing. The year-long negotiations ended on October 10, 2002, with the filing of an agreement ("Agreement") with the PRC. If implemented, the Agreement will set a rate path through 2007 and will resolve the issues surrounding industry deregulation in New Mexico and the Company's merchant power strategy. The Agreement was signed by PNM, the PRC Staff, the New Mexico Attorney General's Office, the New Mexico Industrial Energy Consumers, the City of Albuquerque, and the University of New Mexico. The United States Executive Agencies ("USEA") initially filed a statement objecting to the Agreement, but on October 30, 2002 withdrew their objections and agreed to support the Agreement as if they had signed it. The Agreement must be approved by the PRC and also provides for the signatories to support passage of certain legislation in the New Mexico Legislature. The parties to the Agreement have proposed that the PRC approve the Agreement before the end of the year. The PRC hearing examiner has not yet set a hearing date, but has scheduled a working session and pre-hearing conference for November 19, 2002. 31 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) Under the Agreement, PNM would decrease retail electric rates 6.5% in two phases over the next three years. The first phase would be a 4.0% decrease, effective September 2003. The second phase would be a further 2.5% decrease from current rate levels, effective in September 2005. Rates would then be frozen at that level until the end of 2007. These new rates would place PNM's rates as the sixth lowest in the Southwest and among the lower half of utilities nationwide. The Company expects to achieve necessary cost savings through additional cost efficiencies. The risks and benefits of all off-system sales, other than the dollar amounts of those already embedded in the stipulated rates, inure solely to the Company's shareholders until December 2007. Since the new rate Agreement does not provide for a fuel cost adjustment, the lower fuel costs sought to be captured by shifting to underground mining for the coal supplies at San Juan Generating Station ("SJGS") will flow through to the Company's earnings, largely offsetting the reduction in retail revenues. PNM would be able to seek a general rate adjustment during the rate freeze period, if complying with any new or changed environmental or tax law or regulation, or a new broader application of existing environmental or tax laws or regulations, would compromise its financial integrity. PNM also would be permitted to capitalize all the reasonable costs of mandatory renewable energy resources, including an after-tax cost of capital of 8.64% to be recorded concurrently with the deferral of those costs. PNM would be authorized to recover in the stipulated rates and future retail rates, its New Mexico jurisdictional share of the decommissioning costs associated with the San Juan, La Plata and Navajo Surface Coal Mines. PNM would be allowed to recover up to $100 million of the costs, composed of approximately $69 million in surface coal mine reclamation costs, and approximately $31 million of contract buyout costs. The costs would be amortized over 17 years commencing September 1, 2003 and in equal amounts each year after 2004. PNM would not seek to recover a return on the unamortized reclamation costs, but could seek to recover a return on the unamortized contract buyout costs remaining as of December 31, 2007 in future rate adjustment proceedings. The stipulated rates would also provide for full recovery of nuclear decommissioning costs accrued in accordance with the estimates in the applicable decommissioning cost study during the rate freeze period for PNM's interests in PVNGS Units 1 and 2. The portion of SJGS Unit 4 previously treated as an excluded resource from PNM's New Mexico retail rates would be included as a generation resource to serve PNM's New Mexico retail and wholesale firm requirements customers' load. PNM's contracts to purchase power from Tri-State Generation and Transmission Association, Inc., Delta Person Limited Partnership and firm power from Southwestern Public Service Company would also be included as generation resources to serve PNM's New Mexico retail and wholesale firm requirements customers' load until each contract expires under the Agreement. 32 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) PRC approval or other authorization from the PRC would not be required for PNM's merchant plant investment as long as PNM meets the following conditions: (a) PNM does not invest more than $1.25 billion in merchant plant; (b) PNM has an investment grade credit rating on a stand alone basis and on a consolidated basis with PNM Resources; and (c) PNM spends at least $60 million per year in gas and electric utility, non-merchant plant infrastructure needed to maintain adequate and reliable service. No prior approval for merchant plant participation would be required and expedited PRC approval would be available for financing of merchant plant if certain specified financial conditions are met. If PNM's credit rating on a stand alone or consolidated basis with the Holding Company falls below investment grade, however, approvals are needed for new merchant plant projects and for continuing to participate in merchant plant projects of more than certain dollar value and under certain conditions. PRC approval would not be required for PNM to transfer any part of its interests in merchant plant or PVNGS Unit 3 from time to time to any other legal entity, provided that the following conditions are met: (a) PNM's debt to capital ratio will not exceed 65% after giving effect to the transfer and (b) PNM's investment grade status on a stand-alone basis and on a consolidated basis with the Holding Company will not be impaired by the transfer of merchant plant or PVNGS Unit 3 at the time of transfer. PNM further agreed in the Agreement that it will transfer all its interests in merchant plant out of PNM by January 1, 2010. PNM will accelerate the mandatory transfer to a date one year after PNM has completed expenditures of $1.25 billion on merchant plant. PNM may seek a variance from the PRC at any time prior to January 1, 2010 to extend or vacate the time or terms and conditions requiring the transfer but not beyond January 1, 2015. Under the Agreement, if merchant plant or PVNGS Unit 3 is transferred to a PNM affiliate, PNM's generation resources and the affiliate's generation resources may be jointly dispatched at the merchant affiliate's sole discretion until January 1, 2015. Joint dispatch of all utility, PVNGS Unit 3 or merchant plant resources would be terminable at any time between 2008 and 2015 at PNM's discretion, as long as the utility's dispatch capability is not impaired in any way. PNM agreed to forego its pursuit to recover the costs incurred in preparing to transition to a competitive retail market in New Mexico. This will result in a one-time write off of approximately $16.7 million, pre-tax, upon approval by the PRC of the Agreement. In the Agreement, PNM, PRC utility staff and intervenors agree to actively support the repeal of most of the Restructuring Act of 1999. If the repeal does not occur during the 2003 New Mexico Legislative Session, various modifications to the conditions of the Agreement are triggered depending on how long repeal is delayed. The Company is currently unable to predict the impact these proceedings may have on its plans to expand its generating capacity and its future financial condition and results of operations. 33 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. ("Holding Company") and Subsidiaries and Public Service Company of New Mexico ("PNM") (collectively the "Company") is presented on a combined basis. The 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 the Holding Company pursuant to an order from the New Mexico Public Regulation Commission ("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 PNM Resources, Inc. and Subsidiaries 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 PNM Resources, Inc. and Subsidiaries under 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 considered material to the Company are discussed to the extent known. OVERVIEW PNM Resources, Inc., 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. Upon the completion on December 31, 2001, of a one-for-one share exchange between PNM and the Holding Company, the Holding Company became the parent company of PNM. Prior to the share exchange, the Holding Company had existed as a subsidiary of PNM. The new parent company began trading on the New York Stock Exchange under the same PNM symbol beginning on December 31, 2001. 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, PNM has an obligation to serve its customers under the jurisdiction of the PRC. As a merchant, PNM markets excess production from the utility, as well as unregulated generation, into a competitive market place. The Company also has an electric power trading area focused on purchasing wholesale electricity in the market for future resale or to provide energy to jurisdictional customers in New Mexico when the Company's generation assets cannot satisfy demand. The marketing and trading operations utilize an asset-backed trading strategy, whereby the Company's aggregate net open position for the sale of electricity is covered by 34 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. As it currently operates, 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 due to its immateriality and is combined with the distribution business line for disclosure purposes. The Electric and Gas Services strategy is directed at supplying reasonably priced and reliable energy to retail customers through customer-driven operational excellence, high quality customer service, cost efficient 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, balanced with stringent risk management policies. The Company's future growth plans call for approximately 75% of its new generation portfolio to be committed through long-term contracts, including its sales to retail customers. Growth will be dependent on market development, and upon the Company's ability to generate funds for the Company's future expansion. Although the current environment has led the Company to scale back its expansion plans, the Company will continue to operate in the wholesale market. Expansion of the Company's generating portfolio will depend upon acquiring favorably priced assets at strategic locations and securing long-term commitments for the purchase of power from the acquired plants. 35 RESULTS OF OPERATIONS Three Months Ended September 30, 2002 Compared to Three Months Ended September 30, 2001 Consolidated The Company's net earnings available to common shareholders for the three months ended September 30, 2002 were $17.7 million, a 45.9% decrease in net earnings from $32.6 million the three months ended September 30, 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. Earnings for the third quarter 2002 and 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 September 30, ----------------------------------------------------- 2002 2001 ------------------------- -------------------------- EPS EPS Earnings (Diluted) Earnings (Diluted) ------------ ------------ ------------- ------------ Net Earnings Available for Common Shareholders................................ $17,650 $ 0.45 $32,628 $ 0.82 ------------ ------------ ------------- ------------ Adjustment for Special Gains and Charges (net of income tax effects): Realignment costs............................ (5,337) 0.14 - - Write-off of an Avistar investment........... - - (2,519) (0.06) Western Resources acquisition costs.......... - - (3,061) (0.08) ------------ ------------ ------------- ------------ Total...................................... (5,337) 0.14 (5,580) (0.14) ------------ ------------ ------------- ------------ Net Earnings Available For Common- Shareholders Excluding Special Gains And Charges................................. $22,987 $ 0.59 $38,208 $ 0.96 ============ ============ ============ ============
To adjust reported net earnings and diluted earnings per share to exclude the non-recurring charges, such charges, net of income tax benefit, are added back to reported net earnings under GAAP. 36 The following discussion is based on the financial information presented in the Consolidated Financial Statements - Segment Information note in the Notes to Consolidated Financial Statements. Utility Operations Electric The table below sets forth the operating results for the Electric business segment.
Electric Three Months Ended September 30, --------------------------- 2002 2001 Variance ------------ ------------ ------------ In thousands) Operating revenues: External customers....................... $156,363 $153,535 $ 2,828 Intersegment revenues.................... 177 177 - ------------ ------------ ------------ Total revenues........................... 156,540 153,712 2,828 ------------ ------------ ------------ Cost of energy sold........................ 842 1,146 (304) Intersegment purchases..................... 96,592 95,413 1,179 ------------ ------------ ------------ Total cost of energy..................... 97,434 96,559 875 ------------ ------------ ------------ Gross margin............................... 59,106 57,153 1,953 ------------ ------------ ------------ Administrative and other................... 13,235 11,035 2,200 Depreciation and amortization.............. 8,338 8,219 119 Transmission and distribution costs........ 8,547 10,179 (1,632) Taxes other than income taxes.............. 3,004 2,867 137 Income taxes............................... 7,887 7,618 269 ------------ ------------ ------------ Total non-fuel operating expenses........ 41,011 39,918 1,093 ------------ ----------- ------------ Operating income........................... $ 18,095 $ 17,235 $ 860 ------------ ------------ ------------
Operating revenues increased $2.8 million or 1.8% for the period to $156.5 million. Retail electricity delivery grew 1.2% to 2.05 million MWh in 2002 compared to 2.03 million MWh delivered in the prior year period, resulting in increased revenues of $4.7 million period-over-period. This volume increase was the result of a weather-driven increase in consumption and continued load growth of 1.2%, which is consistent with historical levels. This increase in revenues was partially offset by a decrease in transmission revenues of $2.1 million due to the slowdown in the wholesale market. (Intentionally left blank) 37 The following table shows electric revenues by customer class and average customers: Electric Revenues (In thousands) Three Months Ended September 30, 2002 2001 ------------ ------------ Residential.......................... $53,213 $49,942 Commercial........................... 69,800 68,422 Industrial........................... 21,819 21,836 Other................................ 11,708 13,512 ------------ ------------ $156,540 $153,712 ============ ============ Average customers.................... 385,468 378,336 ============ ============ The following table shows electric sales by customer class: Electric Sales (Megawatt hours) Three Months Ended September 30, 2002 2001 ------------ ------------ Residential.......................... 620,299 593,186 Commercial........................... 928,251 932,204 Industrial........................... 427,481 425,299 Other................................ 74,225 75,750 ------------ ------------ 2,050,256 2,026,439 ============ ============ The gross margin, or operating revenues minus cost of energy sold, increased $2.0 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. Total non-fuel operating expenses increased $1.1 million or 2.7%. Administrative and other increased $2.2 million or 19.9% due to higher administrative costs allocated from Corporate. Transmission and distribution costs decreased $1.6 million or 16.0% primarily due to maintenance performed in 2001 to improve system reliability, which did not recur in 2002. 38 Gas The table below sets forth the operating results for the Gas business segment.
Gas Three Months Ended September 30, ---------------------------- 2002 2001 Variance ------------- ------------- ------------- (In thousands) Operating revenues: External customers........................ $ 36,244 $ 39,649 $ (3,405) Intersegment revenues..................... 666 - 666 ------------- ------------- ------------- Total operating revenues.................... 36,910 39,649 (2,739) Total cost of energy........................ 12,905 14,329 (1,424) ------------- ------------- ------------- Gross margin................................ 24,005 25,320 (1,315) ------------- ------------- ------------- Administrative and other.................... 13,490 12,270 1,220 Depreciation and amortization............... 5,160 5,400 (240) Transmission and distribution costs......... 7,312 8,126 (814) Taxes other than income taxes............... 1,899 1,338 561 Income taxes................................ (2,910) (1,676) (1,234) ------------- ------------- ------------- Total non-fuel operating expenses......... 24,951 25,458 (507) ------------- ------------- ------------- Operating loss.............................. $ (946) $ (138) $ (808) ------------- ------------- -------------
Operating revenues decreased $2.7 million or 6.9% for the period to $36.9 million, primarily as a result of lower natural gas prices during the third quarter of 2002 as compared to the same period in the previous year and a decrease in gas sales volumes of 14.4%, largely from fewer purchases from Generation and Trading to support gas-fired generation. 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. The following table shows gas revenues by customer and average customers: Gas Revenues (In thousands) Three Months Ended September 30, 2002 2001 ------------ ------------ Residential...................... $20,550 $21,717 Commercial....................... 6,248 6,700 Industrial....................... 348 623 Transportation*.................. 4,941 6,024 Other............................ 4,823 4,585 ------------ ------------ $ 36,910 $39,649 ============ ============ Average customers................ 439,637 431,703 ============ ============ 39 The following table shows gas throughput by customer class: Gas Throughput (Thousands of decatherms) Three Months Ended September 30, 2002 2001 ------------ ------------ Residential.................. 2,291 2,337 Commercial................... 1,262 1,176 Industrial................... 94 145 Transportation*.............. 13,753 16,842 Other........................ 801 764 ------------ ------------ 18,201 21,264 ============ ============ *Customer-owned gas. The gross margin, or operating revenues minus cost of energy sold, decreased $1.3 million or 5.2%. This decrease is due mainly to lower consumption of gas for electric generation. The Company currently believes that gas assets are not earning an adequate level of return. As a result, the Company anticipates filing a request for increased rates by year-end 2002. The Company's last gas rate case filing was in October 1997. Total non-fuel operating expense decreased $0.5 million or 2.0%. Administrative and other costs increased $1.2 million or 9.9% for the period primarily due to higher administrative costs allocated from Corporate. The increase in the Corporate allocation was partially offset by a decrease in bad debt expense resulting from improved collection levels. Transmission and distribution costs decreased $0.8 million due to maintenance performed in 2001 to improve system reliability, which did not recur in 2002. Taxes other than income increased $0.5 million or 41.9% due to the absence of favorable audit outcomes by certain tax authorities recognized in 2001. Income taxes, which include taxes for interest charges, decreased $1.2 million or 73.6%, due to the decline in pre-tax income. (Intentionally left blank) 40 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 September 30, ---------------------------- 2002 2001 Variance ------------- ------------- -------------- (In thousands) Operating revenues: External customers..................... $ 96,497 $428,531 $(332,034) Intersegment revenues.................. 96,592 95,413 1,179 ------------- ------------- -------------- Total revenues......................... 193,089 523,944 (330,855) ------------- ------------- -------------- Cost of energy sold...................... 118,851 414,489 (295,638) Intersegment purchases................... 843 177 666 ------------- ------------- -------------- Total cost of energy................... 119,694 414,666 (294,972) ------------- ------------- -------------- Gross margin............................. 73,395 109,278 (35,883) ------------- ------------- -------------- Administrative and other................. 9,605 10,397 (792) Energy production costs.................. 34,534 35,547 (1,013) Depreciation and amortization............ 11,107 10,565 542 Taxes other than income taxes............ 2,628 2,368 260 Income taxes............................. 4,289 18,184 (13,895) ------------- ------------- -------------- Total non-fuel operating expenses...... 62,163 77,061 (14,898) ------------- ------------- -------------- Operating income......................... $ 11,232 $ 32,217 $ (20,985) ------------- ------------- --------------
Operating revenues declined $330.9 million or 63.1% for the period to $193.1 million. This decrease in wholesale electricity sales primarily reflects the slowdown in the wholesale electric market that resulted from steep declines in wholesale prices and trading activity as compared to the prior year. The significantly higher wholesale pricing in 2001 was driven by increased demand in California, a lack of generating assets to serve the market, and the impact of warm weather. By contrast, 2002 has seen relatively mild weather in the West, an abundance of low cost hydropower and weak economic conditions in the region. As a result, average prices in the third quarter were approximately $35 per MWh as opposed to $123 per MWh in the prior year quarter. Trading volume declines reflect the reduction in trading partners in the wholesale market caused by bankruptcy, reduced credit quality of firms in the market, and firms exiting the wholesale trading market. There are also significant unresolved legal, political and regulatory issues that had a dampening effect on activity in the marketplace. As a result, the Company's spot market and short-term sales have declined significantly. The Company delivered wholesale (bulk) power of 2.5 million MWh of electricity for the three months ended September 30, 2002, compared to 3.5 million MWh for the same period in 2001. Although other firms have exited the wholesale market or have had their access to the wholesale market limited due to concerns over credit quality, the Company remains committed to be a participant in this market place. While market liquidity is weak, the Company will focus on long-term relationships with smaller wholesale customers (small investor-owned utilities, municipal utilities and co-ops). At the same time, the Company will continue to monitor market conditions. This commitment to the wholesale market leaves the Company poised to participate in the market as liquidity returns and regulatory issues are resolved. 41 The following table shows revenues by customer class: Generation and Trading Revenues By Market (In thousands) Three Months Ended September 30, 2002 2001 --------------- ------------- Intersegment sales.............. $ 96,592 $ 95,413 Long-term contract.............. 7,261 15,967 Trading*........................ 83,828 412,564 Other........................... 5,408 - --------------- ------------- $ 193,089 $ 523,944 =============== ============= *Includes settled trading contracts and mark-to-market gains/(losses). The following table shows sales by customer class: Generation and Trading Sales By Market (Megawatt hours) Three Months Ended September 30, 2002 2001 --------------- ------------- Intersegment sales................ 2,050,256 2,026,439 Long-term contract................ 160,946 322,930 Trading........................... 2,306,314 3,194,083 --------------- ------------- 4,517,516 5,543,452 =============== ============= The gross margin, or operating revenues minus cost of energy sold, decreased $35.9 million or 32.8%. Lower margins were created primarily by weak pricing, less price volatility and decreased trading activity. Margins were also impacted by higher coal costs at the San Juan Generating Station ("SJGS"). The Company's previously announced transition to an underground mine for the supply of coal at SJGS was delayed, necessitating the continuation of the more expensive surface mine operation. These lower margins were partially offset by a favorable change in the mark-to-market position of the trading portfolio of $6.6 million period-over-period ($6.0 million gain in 2002 versus a $0.6 million loss in 2001). A portion of the gain in 2002 represents the reversal of previously recognized mark-to-market losses. Non-fuel operating expenses decreased $14.9 million or 19.3%. Administrative and other costs decreased $0.8 million or 7.6% due to a decline in power marketing expenses resulting from the slowdown in the wholesale power market and lower costs resulting from increased capital activity for generation expansion. These decreases were partially offset by higher administrative costs allocated from Corporate. Energy production costs decreased $1.0 million or 2.8% for the period primarily due to lower maintenance costs as a result of an outage 42 at SJGS in 2001 that did not recur in 2002. This decrease was partially offset by higher costs at PVNGS due to a planned outage and costs at PNM's Lordsburg plant, which became fully operational in June 2002. Depreciation and amortization increased $0.5 million due to the addition of Lordsburg. Income taxes, which include taxes for interest charges, decreased $13.9 million or 76.4%, due to the decline in pre-tax income. Corporate Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, increased $1.8 million for the period to $23.3 million. This increase was primarily due to severance costs resulting from a realignment of the Company's business structure (the "Realignment") and higher labor resulting from a transfer of employees from operations to Corporate. In accordance with EITF 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity ("EITF 94-3")," the Company incurred a liability of $8.8 million for severance and other related costs associated with the involuntary termination of employees. As of November 1, 2002, $5.1 million of severance-related benefits were paid and charged against the liability. This increase was partially offset by lower bonus expense resulting from lower earnings projections and lower costs resulting from the reduction of certain unregulated activities. Other Non-Operating Other deductions decreased $4.2 million or 44.6% primarily due to charges in 2001 that did not recur in 2002. In 2001, the Company recognized charges for the write-off of an Avistar investment and certain costs related to the Company's now terminated acquisition of Western Resources' electric utility operations. Income Taxes The Company's consolidated income tax expense was $7.4 million for the three months ended September 30, 2002, compared to $22.3 million for the three months ended September 30, 2001. The impact of lower earnings in 2002 contributed to the difference. The Company's effective income tax rates for the three months ended September 30, 2002 and 2001 were 29.23% and 40.54%, respectively. Included in the Company's 2001 taxable income were certain non-deductible costs related to the Company's now terminated acquisition of Western Resources' electric utility operations. Excluding these costs, the Company's effective tax rate was 38.76% in 2001. The decrease in the effective rate quarter over quarter was due to the reduction in earnings in 2002 without a corresponding reduction in permanent tax benefits and to the recognition of certain research and development credits. 43 RESULTS OF OPERATIONS Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30, 2001 Consolidated The Company's net earnings available to common shareholders for the nine months ended September 30, 2002 were $53.5 million, a 63.1% decrease in net earnings from $145.5 million in 2001. This decrease primarily reflects the slowdown in the wholesale electric market, where both prices and trading activity were significantly lower than the prior year period. Despite the slowdown in the wholesale electric market, PNM's electric utility operations recorded operating income growth of 3.5%. 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.
Nine Months Ended September 30, -------------------------------------------------------- 2002 2001 -------------------------- ---------------------------- EPS EPS Earnings (Diluted) Earnings (Diluted) ------------- ------------ -------------- ------------- Net Earnings Available for Common Shareholders................................. $53,463 $ 1.35 $ 145,484 $ 3.66 ------------- ------------ -------------- ------------- Adjustment for Special Gains and Charges (net of income tax effects): Realignment costs............................ (5,337) (0.14) - - Contribution to PNM Foundation................ - - (3,021) (0.07) Write-off of non-recoverable coal mine decommissioning costs...................... - - (7,840) (0.20) Write-off of an Avistar investment............ - - (7,907) (0.20) Western Resources acquisition costs........... - - (4,832) (0.18) ------------- ------------ -------------- ------------- Total....................................... (5,337) (0.14) (23,600) (0.65) ------------- ------------ -------------- ------------- Net Earnings Available For Common- Shareholders Excluding Special Gains and Charges.................................. $58,800 $ 1.49 $ 169,084 $ 4.31 ============= ============ ============= =============
To adjust reported net earnings and diluted earnings per share to exclude the non-recurring charges, such charges, net of income tax benefit, are added back to reported net earnings under GAAP. 44 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 Nine Months Ended September 30, ------------------------------- 2002 2001 Variance -------------- -------------- ------------- (In thousands) Operating revenues: External customers....................... $431,929 $424,249 $ 7,680 Intersegment revenues.................... 530 530 - -------------- -------------- ------------- Total revenues........................... 432,459 424,779 7,680 -------------- -------------- ------------- Cost of energy sold........................ 3,054 3,958 (904) Intersegment purchases..................... 264,554 259,726 4,828 -------------- -------------- ------------- Total cost of energy..................... 267,608 263,684 3,924 -------------- -------------- ------------- Gross margin............................... 164,851 161,095 3,756 -------------- -------------- ------------- Administrative and other................... 38,383 35,975 2,408 Depreciation and amortization.............. 25,239 24,310 929 Transmission and distribution costs........ 25,864 26,619 (755) Taxes other than income taxes.............. 9,382 8,527 855 Income taxes............................... 19,141 20,389 (1,248) -------------- -------------- ------------- Total non-fuel operating expenses........ 118,009 115,820 2,189 -------------- -------------- ------------- Operating income........................... $ 46,842 $ 45,275 $ 1,567 -------------- -------------- -------------
Operating revenues increased $7.7 million or 1.8% for the period to $432.5 million. Retail electricity delivery grew 1.8% to 5.62 million MWh in 2002 compared to 5.52 million MWh delivered in the prior year period, resulting in increased revenues of $11.1 million year-over-year. This volume increase was the result of a weather-driven increase in consumption and continued load growth of 1.8%. Period over period, customer growth was 2.4%. This increase in revenues was partially offset by a decrease in transmission revenues of $3.1 million due to the slowdown in the wholesale market. (Intentionally left blank) 45 The following table shows electric revenues by customer class and average customers: Electric Revenues (In thousands) Nine Months Ended September 30, 2002 2001 ------------- ------------- Residential..................... $149,631 $142,785 Commercial...................... 187,382 183,372 Industrial...................... 62,239 62,161 Other........................... 33,207 36,461 ------------- ------------- $432,459 $424,779 ============= ============= Average customers............... 383,572 376,520 ============= ============= The following table shows electric sales by customer class: Electric Sales (Megawatt hours) Nine Months Ended September 30, 2002 2001 ------------- ------------- Residential...................... 1,743,712 1,676,271 Commercial....................... 2,462,728 2,447,231 Industrial....................... 1,225,398 1,210,266 Other............................ 183,590 182,450 ------------- ------------- 5,615,428 5,516,218 ============= ============= The gross margin, or operating revenues minus cost of energy sold, increased $3.8 million or 2.3%, 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. Total non-fuel operating expenses increased $2.2 million or 1.9%. Administrative and other costs increased $2.4 million or 6.7% due to higher administrative costs allocated from Corporate, partially offset by lower bad debt expense as a result of collection improvements and the absence of losses from the bankruptcy of a significant customer in 2001. Depreciation and amortization increased $0.9 million or 3.8% for the period due to a higher depreciable plant base. Transmission and distribution costs decreased $0.8 million or 2.8% primarily due to maintenance performed in 2001 to improve system reliability, which did not recur in 2002. Taxes other than income increased $0.9 million or 10.0% primarily reflecting the absence of favorable audit outcomes by certain tax authorities recognized in 2001. Income taxes, which include taxes associated with interest charges, decreased $1.2 million or 6.1% due to lower pre-tax income. 46 Gas The table below sets forth the operating results for the Gas business segment.
Gas Nine Months Ended September 30, --------------------------------- 2002 2001 Variance -------------- --------------- -------------- (In thousands) Operating revenues: External customers....................... $ 189,413 $ 318,670 $ (129,257) Intersegment revenues.................... 1,136 - 1,136 -------------- --------------- -------------- Total revenues............................. 190,549 318,670 (128,121) Total cost of energy....................... 96,576 220,547 (123,971) -------------- --------------- -------------- Gross margin............................... 93,973 98,123 (4,150) -------------- --------------- -------------- Administrative and other................... 39,147 39,797 (650) Depreciation and amortization.............. 15,548 16,023 (475) Transmission and distribution costs........ 21,836 21,829 7 Taxes other than income taxes.............. 5,985 4,990 995 Income taxes............................... 526 2,819 (2,293) -------------- --------------- -------------- Total non-fuel operating expenses........ 83,042 85,458 (2,416) -------------- --------------- -------------- Operating income........................... $ 10,931 $ 12,665 $ (1,734) -------------- --------------- --------------
Operating revenues decreased $128.1 million or 40.2% for the period to $190.5 million, primarily as the result of lower natural gas prices in 2002 as compared to 2001 and a decrease in gas sales volumes of 10.2%, largely resulting from fewer purchases from Generation and Trading to support gas-fired generation. Despite the volume decline, customer growth was approximately 2.1%. PNM 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. The following table shows gas revenues by customer and average customers: Gas Revenues (In thousands) Nine Months Ended September 30, 2002 2001 -------------- ------------- Residential.................... $118,274 $188,113 Commercial..................... 36,838 56,375 Industrial..................... 1,412 26,541 Transportation*................ 13,686 16,437 Other.......................... 20,339 31,204 -------------- ------------- $190,549 $318,670 ============== ============= Average customers.............. 442,364 433,549 ============== ============= 47 The following table shows gas throughput by customer class: Gas Throughput (Thousands of decatherms) Nine Months Ended September 30, 2002 2001 -------------- ------------- Residential.................... 18,791 18,357 Commercial..................... 7,826 6,867 Industrial..................... 390 3,665 Transportation*................ 35,226 41,243 Other.......................... 3,905 3,541 -------------- ------------- 66,138 73,673 ============== ============= *Customer-owned gas. The gross margin, or operating revenues minus cost of energy sold, decreased $4.2 million or 4.2%. This decrease is due mainly to lower consumption of gas for electric generation partially offset by a 2.0% growth in customer base. Total non-fuel operating expenses decreased $2.4 million or 2.8%. Administrative and other costs decreased $0.7 million or 1.6%. This decrease is primarily due to lower bad debt expense as a result of collection improvements and the absence of losses from the bankruptcy of a significant customer in 2001. This cost improvement was largely offset by higher allocated Corporate administrative costs. Taxes other than income increased $1.0 million or 19.9% due to the absence of favorable audit outcomes by certain tax authorities recognized in 2001. Income taxes, which include income taxes for interest charges, decreased $2.3 million or 81.3% due to lower pre-tax income. (Intentionally left blank) 48 Generation and Trading Operations The table below sets forth the operating results for the Generation and Trading business segment.
Generation and Trading Nine Months Ended September 30, --------------------------------- 2002 2001 Variance --------------- --------------- --------------- (In thousands) Operating revenues: External customers....................... $245,411 $1,280,141 $(1,034,730) Intersegment revenues.................... 264,554 259,726 4,828 --------------- --------------- --------------- Total revenues........................... 509,965 1,539,867 (1,029,902) --------------- --------------- --------------- Cost of energy sold........................ 310,769 1,136,400 (825,631) Intersegment purchases..................... 1,666 530 1,136 --------------- --------------- --------------- Total cost of energy..................... 312,435 1,136,930 (824,495) --------------- --------------- --------------- Gross margin............................... 197,530 402,937 (205,407) --------------- --------------- --------------- Administrative and other................... 25,968 25,388 580 Energy production costs.................... 102,448 107,135 (4,687) Depreciation and amortization.............. 32,587 31,981 606 Taxes other than income taxes.............. 8,244 6,611 1,633 Income taxes............................... 6,633 82,805 (76,172) --------------- --------------- --------------- Total non-fuel operating expenses........ 175,880 253,920 (78,040) --------------- --------------- --------------- Operating income........................... $ 21,650 $ 149,017 $ (127,367) --------------- --------------- ---------------
Operating revenues declined $1.0 billion or 66.9% for the period to $510.0 million. This decrease in wholesale electricity sales primarily reflects the slowdown in the wholesale electric market, which resulted from steep declines in wholesale prices and trading activity as compared to the prior year period. The significantly higher wholesale pricing in 2001 was driven by increased demand in California, a lack of generating assets to serve the market, and the impact of warm weather. By contrast, 2002 has seen relatively mild weather in the West, an abundance of low cost hydropower and weak economic conditions in the region. As a result, the average price realized by the Company fell to approximately $29 per MWh in 2002 versus $133 per MWh in 2001. Trading volume declines reflect the reduction in trading partners in the wholesale market caused by bankruptcy, reduced credit quality of firms in the market and firms exiting the wholesale trading market. There are also significant unresolved legal, political and regulatory issues that had a dampening effect on activity in the marketplace. As a result, the Company's spot market and short-term sales have declined significantly. The Company delivered wholesale (bulk) power of 7.2 million MWh of electricity for the nine months ended September 30, 2002, compared to 9.8 million MWh for the same period in 2001. Although other firms have exited the wholesale market or have had their access to the wholesale market limited due to concerns over credit quality, the Company remains committed to be a participant in this market place. While market liquidity is weak, the Company will focus on long-term relationships with smaller wholesale customers (small investor-owned utilities, municipal utilities and co-ops). At the same time, the Company will continue to monitor market conditions. This commitment to the wholesale market leaves the Company poised to participate in the market as liquidity returns and regulatory issues are resolved. 49 The following table shows revenues by customer class: Generation and Trading Revenues By Market (In thousands) Nine Months Ended September 30, 2002 2001 -------------- -------------- Intersegment sales................. $ 264,554 $ 259,726 Long-term contract................. 32,160 61,762 Trading*........................... 199,702 1,217,447 Other.............................. 13,549 932 -------------- -------------- $ 509,965 $1,539,867 ============== ============== *Includes settled trading contracts and mark-to-market gains/(losses). The following table shows sales by customer class: Generation and Trading Sales By Market (Megawatt hours) Nine Months Ended September 30, 2002 2001 ---------------- --------------- Intersegment sales............... 5,615,428 5,516,218 Long-term contract............... 669,099 1,169,877 Trading.......................... 6,569,009 8,656,623 ---------------- --------------- 12,853,536 15,342,718 ================ =============== The gross margin, or operating revenues minus cost of energy sold, decreased $205.4 million or 51.0%. Lower margins were created primarily by weak pricing, less price volatility and lower trading liquidity. Margins were also impacted by higher coal costs at SJGS. The Company's previously announced transition to an underground mine for supply of coal at SJGS was delayed, necessitating the continuation of the more expensive surface mine operation. These lower margins were partially offset by a favorable change in the mark-to-market position of the trading portfolio of $48.9 million period-over-period ($22.1 million gain in 2002 versus $26.8 million loss in 2001). A portion of the gain in 2002 represents the reversal of previously recognized mark-to-market losses. Total non-fuel operating expenses decreased $78.0 million or 30.7%. Administrative and other costs increased $0.6 million or 2.3% for the period. This increase is primarily due to higher corporate cost allocations, partially offset by an adjustment to prior year SJGS participant billings (the Company is the operator of SJGS and shares costs with other owners) and lower costs resulting from increased capital activity for generation expansion. Energy production costs decreased $4.7 million or 4.4% for the period reflecting the benefits of the acceleration into 2001 of a planned outage at SJGS and an adjustment to prior year PVNGS billings from Arizona Public Service Company the 50 operator of PVNGS. These cost decreases were partially offset by planned and unplanned outages at PNM's Four Corners facility and costs at Lordsburg, which became fully operational in June 2002. Depreciation and amortization increased $0.6 million or 1.9% due to the addition of Lordsburg. Taxes other than income increased $1.6 million or 24.7% reflecting adjustments recorded in the prior year for favorable audit outcomes by certain tax authorities. Income taxes, which include income taxes for interest charges, decreased $76.2 million or 92.0% due to a decline in pre-tax income. Corporate Corporate administrative and general costs, which represent costs that are driven primarily by corporate-level activities, decreased $2.2 million for the period to $68.9 million. This decrease was primarily due to lower retiree benefits expense and lower bonus expense in the current year resulting from lower earnings projections and lower costs resulting from the reduction of certain unregulated activities. These decreases were partially offset by severance costs resulting from the Realignment, higher legal costs due to increased business exposures and outside services related to debt refinancing activities. In accordance with EITF 94-3, the Company incurred a liability of $8.8 million for severance and other related costs associated with the involuntary termination of employees. As of November 1, 2002, $5.1 million of severance-related benefits were paid and charged against the liability. Other Non-Operating Other income decreased by $4.8 million or 12.0% reflecting lower year-over-year returns on investments reflecting market conditions. Other deductions decreased $48.0 million or 88.6% primarily due to charges in 2001 that did not recur in 2002. In 2001, the Company recognized charges for the write-off of non-recoverable coal mine decommissioning costs, a contribution to the PNM Foundation, the write-off of an Avistar investment, and certain costs related to the Company's now terminated acquisition of Western Resources' electric utility operations. Income Taxes The Company's consolidated income tax expense was $27.1 million for the nine months ended September 30, 2002, compared to $85.9 million for the nine months ended September 30, 2001. The impact of lower earnings in 2002 contributed to the difference. The Company's effective income tax rates for the nine months ended September 30, 2002 and 2001 were 33.48% and 37.06%, respectively. Included in the Company's 2001 taxable income were certain non-deductible costs related to the Company's now terminated acquisition of Western Resources' electric utility operations. In addition, the Company determined that $6.6 million of allowances taken against certain income tax related regulatory assets were no longer required due to changes in the evaluation of its regulatory strategy in light of the Holding Company filing in May 2001. In 2000, when the allowance was established, management believed these income- tax-related regulatory assets would not be recoverable based on the probable regulatory outcome of industry restructuring in New Mexico. Currently, management fully expects to recover these costs in future rate cases, a situation that was not possible prior to the delay of open access in New Mexico. Excluding these costs, the Company's effective tax rate was 38.88% in 2001. The decrease in the effective rate was due to the reduction in earnings in 2002 without a corresponding reduction in permanent tax benefits and the recognition of certain research and development credits. 51 FUTURE EXPECTATIONS On July 9, 2002, the Company announced that it expects 2002 earnings for the twelve months to be in the range of $1.90 to $2.10. Although the Company's electric utility continues to perform well, the depressed level of wholesale prices in the West, coupled with the significantly decreased trading activity in that market, has severely limited the potential of Generation and Trading. Several factors, including an abundance of available hydropower from the Pacific Northwest, cooler weather through May and June, low natural gas prices, the number of new generating plants coming on line, and the lingering slowdown in the regional economy have all contributed to keeping power prices down in 2002. Additionally, fewer credit-worthy counterparties and legal, political and regulatory uncertainty regarding the Western marketplace have significantly reduced market liquidity and trading volume as some companies have curtailed their activity or exited the business altogether. These factors resulted in a 26.3% reduction in wholesale sales for the Company for the nine months ended September 30, 2002 compared to the nine months ended September 30, 2001. Other factors contributing to the year over year decrease in earnings include increased coal costs and lower earnings in the gas utility business as a result of a mild spring. On October 10, 2002, the Company filed a rate agreement with the PRC, which if approved, will set an electric utility rate path for the Company through 2007 (see Merchant Plant Filing and Electric Rate Settlement). Under the rate agreement, PNM will reduce its retail electric rates by 6.5% in two phases over the next three years. The Company expects to realize certain cost savings, primarily through lower coal fuel costs by switching to underground mining at SJGS, largely offsetting the revenue reduction and allowing for an 10.5% rate of return on its electric jurisdictional assets. Incorporating the 10.5% return on the regulated electric utility with the Company's other existing productive assets is expected to generate base earnings capacity of approximately $2.00 per share. PNM will incur the risks and benefits of all off-system sales, cost structure changes, plant availability and other earnings risks and opportunities. PNM also plans to file a request for rate relief in its gas utility business by the end of the year 2002. Any improvement in gas returns through rate relief is not included in the base earnings capacity. However, the ability to achieve or sustain this earnings level is largely dependent on the timing of the shift to underground mining at SJGS, the ability to recognize the expected cost savings related to the underground mining operation and a favorable outcome from its planned gas rate filing. To preserve the Company's strong financial position, management intends to control expenses through on-going savings from the Realignment and other cost control measures and plans to limit capital expenditures. Construction expenditures in 2002, originally budgeted at $391 million, were reduced by $111 million to $280 million for the year. Planned construction expenditures through 2003 were reduced in total by over $400 million. The reduced capital expenditures are related to a cut back of growth initiatives on the generation side and will not affect PNM's ability to continue to provide reliable service to its customers. On-going annual capital expenditures associated with the electric and gas utility operations are expected to be in the range of $80 to $100 million. 52 Although the current environment has led the Company to scale back its expansion plans, the Company will continue to operate in the wholesale market. Expansion of the Company's generating portfolio will depend upon acquiring favorably priced assets at strategic locations and securing long-term commitments for the purchase of power from those new plants. 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 discussed above. LIQUIDITY AND CAPITAL RESOURCES At September 30, 2002, the Company had cash and short-term investments of $139.5 million compared to $71.2 million in cash and short-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. Cash provided from operating activities in the nine months ended September 30, 2002 was $104.0 million compared to cash provided by operating activities of $296.9 million for the nine months ended September 30, 2001. This decrease was primarily the result of current wholesale market conditions. Also, contributing to the decrease was the Company's $24.6 million contribution to its pension and postretirement benefit plans. In addition, the Company did not make its first quarter 2001 estimated federal income tax payment of $32.0 million 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 $136.6 million in 2002 compared to $153.9 million in 2001. Cash used for investing activities includes construction expenditures for new generating plants of $96.7 million in 2002 compared to $68.0 million in 2001. These cash outflows were partially offset by the redemption of short-term investments of $45.0 million. Expenditures in 2001 reflect the acquisition of certain transmission assets and other related investing activities of $13.9 million. 53 Cash generated by financing activities was $36.5 million in 2002 compared to $28.1 million of cash used in 2001. Financing activities in 2002 were primarily short-term borrowings of $65.0 million 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 reflecting the events in the financial markets after September 11, 2001. As a result, the Company had lowered its expected rate of return on its retiree benefit plans assets. By year end 2001, markets had recovered significantly. As a result, in 2002 the Company adjusted its return assumption to its historic view of a 9% long-term rate of return. In addition, in January 2002, the Company made an aggregate contribution of $23.5 million to fund pension and other postretirement benefit plans. An additional aggregate contribution of $1.1 million was made in September 2002. The effect of the change in the expected rate of return and the additional cash contributions was a decrease in pension and other postretirement benefits expense for the nine months ended September 30, 2002 compared to the same period in the prior year. 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 and expanding its wholesale generation capabilities; upgrading and expanding the electric and gas transmission and distribution systems; and purchasing nuclear fuel. To preserve a strong financial position, the Company plans to reduce its capital expenditures for planned generation expansion. Projections for total capital requirements for 2002 are $298 million and projections for construction expenditures for 2002, originally predicted to be $391 million, have been reduced by $111 million to $280 million for the year. Planned construction expenditures through 2003 were reduced in total by over $400 million. For 2002-2006 projections, total capital requirements are $1.5 billion and construction expenditures are $1.4 billion, including the combustion turbines discussed below. These estimates are under continuing review and subject to on-going adjustment. 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 over the next five years depending on market conditions. PNM has expended $208.8 million as of September 30, 2002 of which $131.5 million was for equipment purchases. In November 2001, PNM broke ground to build Afton Generating Station, a 135 MW simple cycle gas turbine plant in southern New Mexico, which is expected to be operational by the end of November 2002. In February 2002, PNM broke ground to build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired generating plant in southwestern New Mexico. On June 27, 2002, Lordsburg became fully operational and commenced serving the wholesale power market. Construction 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. These plants were not built to serve New Mexico retail customers and so have not been added to rate base. However, it is possible that future growth in the New Mexico retail market will cause these plants to be needed to serve New Mexico retail customers. In that case, the plants will have to be certified by the PRC and would be added to rate base at that time. 54 In the first nine months of 2002, the Company utilized cash generated from operations, cash on hand, as well as its liquidity arrangements to cover its construction commitments. The Company anticipates that internal cash generation and current debt capacity will be sufficient to meet all its 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 current and future liquidity arrangements. Liquidity As of November 1, 2002, PNM had $180 million of liquidity arrangements, consisting of $150 million from an unsecured revolving credit facility ("Credit Facility") and $30 million in local lines of credit. PNM has been in discussions with its banks regarding renewal of the Credit Facility, which will expire in March 2003. There were $100 million in borrowings against the Credit Facility as of November 1, 2002. In addition, the Holding Company has $25 million in local lines of credit. The Company's ability, if required, to access the capital markets 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 stable by Moody's Investor Services, Inc. ("Moody's") and Standard and Poor's Ratings Services ("S&P") and positive by Fitch, Inc. ("Fitch"). 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 and to ultimately 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 ratings. 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 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. 55 Long-term Obligations and Commitments The following table shows PNM's long-term debt and operating leases as of September 30, 2002. As of September 30, 2002, PNM Resources, Inc. and Subsidiaries have no long-term obligations except those acquired through consolidation with PNM.
Payments Due --------------------------------------------------------------- (In thousands) Contractual Less than After Obligations Total 1 year 2-3 years 4-5 years 5 years ------------ ------------ ----------- ----------- ------------- Long-Term Debt.................. $ 953,926 $ - $ - $268,420 $ 685,506 Operating Leases................ 508,883 32,811 67,452 70,969 337,651 ------------ ------------ ----------- ----------- ------------- Total Contractual Cash Obligations.................. $1,462,809 $32,811 $67,452 $339,389 $1,023,157 ============ ============ =========== =========== =============
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 $9.9 million for the nine months ended September 30, 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 $224 million as of September 30, 2002. PNM has entered various long-term power purchase agreements obligating it to buy electricity for aggregate fixed payments of $27.7 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 $194.1 million in fixed payments plus the cost of production and a return. These contracts expire December 2003 through June 2010. PNM's trading portfolio as of September 30, 2002 included open contract positions to buy $38.3 million of electricity and to sell $29.6 million of electricity. In addition, PNM had open forward positions classified as normal sales of electricity under the derivative accounting rules of $36.1 million and normal purchases of electricity of $70.6 million. 56 PNM contracts for the purchase of gas to serve its retail 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 PNM recovers 100% of its cost of gas. SJGS Coal Supply PNM has a coal supply contract for the needs of 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. In August 2001, PNM signed an agreement with San Juan Coal Company ("SJCC"), the owner of the coal mine that supplies coal to SJGS, and Tucson Electric Power Company to replace two surface mining operations with a single underground mine located adjacent to the plant. Underground mining is expected to provide a higher quality coal at a lower cost per ton. The revised coal contract, entered into as a result of the move to an underground mine, is expected to save PNM between $400 million and $500 million in fuel costs over the next 16 years. Besides saving on fuel costs, the cleaner-burning, less abrasive coal is expected to reduce PNM's share of the plant's maintenance and operating expenses. The underground mine began ramp-up operations on October 14, 2002. The current plan includes a ramp-up to full station supply in approximately six months. The last surface mine deliveries are expected by January 2003. New Long-Term Power Contract On October 21, 2002, PNM entered into an agreement with FPL Energy LLC ("FPL"), a subsidiary of FPL Group, Inc., to develop a 200 MW wind generation facility in New Mexico. FPL Energy will build, own and operate the New Mexico Wind Energy Center ("NMWE"), consisting of 136 wind-powered turbines on a site in eastern New Mexico. PNM will buy all the power generated by the NMWE under a 25-year contract. Construction of the wind energy site is expected to begin later this year. Construction on a facility of this size typically takes six to nine months to complete. This project represents a significant step forward in reducing PNM's reliance on fossil fuel generation while protecting PNM's competitive cost of generation. For PNM, the NMWE will provide a long-term, competitively priced power source both for New Mexicans and for the wholesale power market in the Southwest. PNM will ask the PRC to approve a voluntary tariff that will allow PNM retail customers to buy wind-generated electricity for a small monthly premium. Power from the facility not subscribed by PNM retail customers under the voluntary program will be sold on the wholesale market, either within New Mexico or outside the state. PNM is buying this clean energy for several reasons: its environmental benefits for New Mexico; interest within the state in renewable energy; prospects for renewable energy on the wholesale energy market; and the strength this particular wind contract will bring to PNM's competitive generation portfolio and its overall fuel mix. 57 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 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 retail 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 Systems Power Pool ("WSPP") contains a contingent requirement that could require PNM to provide security if its debt were to fall below 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 September 30, 2002, PNM had $5.7 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. Planned Financing Activities PNM has $268.4 million of long-term debt that matures in August 2005. All other long-term debt of PNM 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 and regulatory agreements would ultimately limit the amount of additional debt PNM would issue. 58 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. The Company received regulatory approval to refund the tax-exempt bonds on October 29, 2002. This approval is good for one year. In order to take advantage of current low interest rates, PNM entered into five forward starting interest rate swaps in the fourth quarter of 2001 and 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 4.95% 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. For the nine months ended September 30, 2002, PNM recognized $0.4 million of hedge ineffectiveness in earnings. At September 30, 2002, the fair market value of these derivative financial instruments was approximately $20.3 million unfavorable to the Company. 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 benchmark. The five forward starting interest rate swaps have a termination date of May 15, 2003 for a combined notional amount of $182.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transaction 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. On November 1, 2002, the Company filed for approval from the PRC to enter into a transaction providing for the securitization of PNM's retail electric service accounts receivable, wholesale electric service accounts receivables and retail gas services accounts receivable ("Securitization") to reduce the amount of debt outstanding under the Credit Facility and to raise cash for PNM's ongoing working capital requirements and other capital requirements. The total capacity, or maximum that could be borrowed, under the Securitization will not exceed $100 million. In the proposed transaction, PNM would sell its accounts receivables from time to time. Dividends The Holding Company's board of directors regularly reviews the dividend policy. The declaration of common dividends is dependent upon a number of factors including the ability of the Holding Company's subsidiaries to pay dividends. Currently, PNM is the Holding 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 the Holding Company. PNM cannot pay dividends that will 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 for that year without prior PRC approval. Additionally, PNM has various financial covenants, which limit the transfer of assets, through dividends or other means. 59 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 earnings, its financial circumstances and performance, the effect of regulatory decisions and legislative activities, future growth plans, the related capital requirements, standard business considerations and market economic conditions generally. Consistent with the PRC's holding company order, PNM paid dividends of $127.0 million to the Holding Company on December 31, 2001. On March 4, 2002, the PNM board of directors declared a dividend of $5.5 million, which was paid on March 19, 2002. On June 10, 2002, the PNM board of directors declared a dividend of $24.7 million, which was paid on June 28, 2002. On February 19, 2002, the Holding Company's board of directors approved a 10 percent increase in the common stock dividend. The increase raised the quarterly dividend to $0.22 per share, for an indicated annual dividend of $0.88 per share. The 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 September 30, 2002 and December 31, 2001 is shown below: September 30, December 31, 2002 2001 ------------- -------------- Common Equity.................... 51.4% 50.8% Preferred Stock.................. 0.6 0.6 Long-term Debt................... 48.0 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 $224 million as of September 30, 2002 and $225 million as of December 31, 2001. OTHER ISSUES FACING THE COMPANY RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY State 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 60 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 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 would 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. Approximately $143 million of costs associated with the power supply and energy services businesses under the Restructuring Act, as amended 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. On October 10, 2002, PNM announced that it had agreed with the PRC Staff, the Attorney General, and other consumer groups on a stipulation that includes agreement to support repeal of the Restructuring Act, as amended. The stipulation, which includes agreement on a five year rate path, procedures for the Company's participation in merchant plant activities and other regulatory issues, must first be approved by the PRC before the parties' obligations to support repeal becomes effective. The parties signing the stipulation have proposed that the PRC approve the stipulation before the end of the year. The PRC hearing examiner has not yet set a hearing date, but has scheduled a working session and pre-hearing conference for November 19, 2002. The next legislative session begins on January 21, 2003. The Company is unable to predict at this time if restructuring will occur as provided in current law or, if so, what form it will take. (See Merchant Plant Filing and Electric Rate Settlement below). 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. An interim committee of the legislature is studying 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. 61 Federal On April 25, 2002, by a vote of 88-11, the U.S. Senate (the "Senate") passed amendments to HR4, 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 version voted on the House of Representative (the "House"). As adopted by the Senate, H.R.4 contains provisions revising the authority of the Federal Energy Regulation Commission (the "FERC") 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 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 the 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; and extends protections against liability for nuclear accidents under the Price-Anderson Act. The differences in the two versions of H.R.4 are the subject of conference committee discussions. The Company is unable to predict when or if an agreement will be reached between the House and the Senate and if so, what form energy legislation will take, if energy legislation will be passed or if passed, whether 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. On October 10, 2002, the FERC issued a Declaratory Order, on Regional Transmission Organization in response to WestConnect's October 15, 2001 Joint Petition for Declaratory Order to Form WestConnect RTO, LLC Pursuant to Order 2000. The Company continues to participate in this process. To remedy what the FERC sees as undue discrimination in the provision of interstate transmission services and to ensure just and reasonable rates for sales of electric energy within and among regional power markets, the FERC has approved a Notice of Proposed Rulemaking ("NOPR") for Standard Market Design. The proposed rule would put all transmission customers, including bundled retail customers, under new pro forma transmission rates for new transmission service. All transmission will be operated under independent transmission providers (including RTOs) and congestion management will be handled under locational marginal pricing with tradable congestion revenue rights. The Company will be making comments on the Standard Market Design NOPR along with the other WestConnect companies and will continue to participate in the rulemaking process. The Company is also following rulemakings of the FERC on Standards of Conduct and Standardizing Generation Interconnection Agreements and Procedures and has submitted comments or has commented in conjunction with WestConnect and Edison Electric Institute. 62 MERCHANT PLANT FILING AND ELECTRIC RATE SETTLEMENT Senate Bill ("SB266"), enacted by the 2001 session of the New Mexico legislature, allowed public utilities to "invest in, construct, acquire or operate" generating plants not intended to provide retail electric service ("merchant plant"), 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 PRC can ensure the utility will meet its duty to provide service when the utility invests in merchant plant, how that plant will be financed and how transactions between regulated services and merchant plants will be conducted. The PRC initiated proceedings to address these issues. In November 2001, PNM began settlement negotiations with the PRC utility staff and intervenors in order to resolve its merchant plant filing and other matters. Discussions included the future framework for restructuring the electric industry in New Mexico under the Restructuring Act, a future retail electric rate path and PNM's merchant plant filing. The year-long negotiations ended on October 10, 2002, with the filing of an agreement ("Agreement") with the PRC. If implemented, the Agreement will set a rate path through 2007 and will resolve the issues surrounding industry deregulation in New Mexico and the Company's merchant power strategy. The Agreement was signed by PNM, the PRC Staff, the New Mexico Attorney General's Office, the New Mexico Industrial Energy Consumers, the City of Albuquerque, and the University of New Mexico. The United States Executive Agencies ("USEA") initially filed a statement objecting to the Agreement, but on October 30, 2002 withdrew their objections and agreed to support the Agreement as if they had signed it. The Agreement must be approved by the PRC and also provides for the signatories to support passage of certain legislation in the New Mexico Legislature. The parties to the Agreement have proposed that the PRC approve the Agreement before the end of the year. The PRC hearing examiner has not yet set a hearing date, but has scheduled a working session and pre-hearing conference for November 19, 2002. Under the Agreement, PNM would decrease retail electric rates 6.5% in two phases over the next three years. The first phase would be a 4.0% decrease, effective September 2003. The second phase would be a further 2.5% decrease from current rate levels, effective in September 2005. Rates would then be frozen at that level until the end of 2007. These new rates would place PNM's rates as the sixth lowest in the Southwest and among the lowest half of utilities nationwide. The Company expects to achieve necessary cost savings through additional cost efficiencies. The risks and benefits of all off-system sales, other than the dollar amounts of those already embedded in the stipulated rates, inure solely to the Company's shareholders until December 2007. Since the new rate Agreement does not provide for a fuel cost adjustment, the lower fuel costs sought to be captured by shifting to underground mining for the coal supplies at SJGS will flow through to the Company's earnings largely offsetting the reduction in retail revenues. 63 PNM would be able to seek a general rate adjustment during the rate freeze period if complying with any new or changed environmental or tax law or regulation, or a new broader application of existing environmental or tax laws or regulations, would compromise its financial integrity. PNM also would be permitted to capitalize all the reasonable costs of mandatory renewable energy resources, including an after-tax cost of capital of 8.64% to be recorded concurrently with the deferral of those costs. PNM would be authorized to recover in the stipulated rates and future retail rates, its New Mexico jurisdictional share of the decommissioning costs associated with the San Juan, La Plata and Navajo Surface Coal Mines. PNM would be allowed to recover up to $100 million of the costs, composed of approximately $69 million in surface coal mine reclamation costs, and approximately $31 million of contract buyout costs. The costs would be amortized over 17 years commencing September 1, 2003 and in equal amounts each year after 2004. PNM would not seek to recover a return on the unamortized reclamation costs, but could seek to recover a return on the unamortized contract buyout costs remaining as of December 31, 2007 in future rate adjustment proceedings. The stipulated rates would also provide for full recovery of nuclear decommissioning costs accrued in accordance with the estimates in the applicable decommissioning cost study during the rate freeze period for PNM's interests in PVNGS Units 1 and 2. The portion of SJGS Unit 4 previously treated as an excluded resource from PNM's New Mexico retail rates would be included as a generation resource to serve PNM's New Mexico retail and wholesale firm requirements customers' load. PNM's contracts to purchase power from Tri-State Generation and Transmission Association, Inc., Delta Person Limited Partnership and firm power from Southwestern Public Service Company would also be included as generation resources to serve PNM's New Mexico retail and wholesale firm requirements customers' load until each contract expires under the Agreement. PRC approval or other authorization from the PRC would not be required for PNM's merchant plant investment as long as PNM meets the following conditions: (a) PNM does not invest more than $1.25 billion in merchant plant; (b) PNM has an investment grade credit rating on a stand alone basis and on a consolidated basis with PNM Resources; and (c) PNM spends at least $60 million per year in gas and electric utility, non-merchant plant infrastructure needed to maintain adequate and reliable service. No prior approval for merchant plant participation would be required and expedited PRC approval would be available for financing of merchant plant if certain specified financial conditions are met. If PNM's credit rating on a stand alone or consolidated basis with the Holding Company falls below investment grade, however, approvals are needed for new merchant plant projects and for continuing to participate in merchant plant projects of more than certain dollar value and under certain conditions. PRC approval would not be required for PNM to transfer any part of its interests in merchant plant or PVNGS Unit 3 from time to time to any other legal entity, provided that the following conditions are met: (a) PNM's debt to capital ratio will not exceed 65% after giving effect to the transfer and (b) PNM's investment grade status on a stand-alone basis and on a consolidated basis with the Holding Company will not be impaired by the transfer of merchant plant or PVNGS Unit 3 at the time of transfer. PNM further agreed in the Agreement that it will transfer all its interests in merchant plant out of PNM by January 1, 2010. PNM will accelerate the mandatory transfer to a date one year after PNM has completed expenditures of $1.25 billion on merchant plant. PNM may seek a variance from the PRC at any time prior to January 1, 2010 to extend or vacate the time or terms and conditions requiring the transfer but not beyond January 1, 2015. 64 Under the Agreement, if merchant plant or PVNGS Unit 3 is transferred to a PNM affiliate, PNM's generation resources and the affiliate's generation resources may be jointly dispatched at the merchant affiliate's sole discretion until January 1, 2015. Joint dispatch of all utility, PVNGS Unit 3 or merchant plant resources would be terminable at any time between 2008 and 2015 at PNM's discretion, as long as the utility's dispatch capability is not impaired in any way. PNM agreed to forego its pursuit to recover the costs incurred in preparing to transition to a competitive retail market in New Mexico. This will result in a one-time write off of approximately $16.7 million, pre-tax, upon approval by the PRC of the Agreement. In the Agreement, PNM, PRC utility staff and intervenors agree to actively support the repeal of most of the Restructuring Act of 1999. If the repeal does not occur during the 2003 New Mexico Legislative Session, various modifications to the conditions of the Agreement are triggered depending on how long repeal is delayed. In summary, the terms of this Agreement and the Company's continuing efforts to control expenses offer significant benefits to both customers and shareholders in the form of lower rates, a predictable rate path, and the resolution of important issues affecting implementation of the Company's strategic plan over the next several years. The Company is currently unable to predict the impact these proceedings may have on its plans to expand its generating capacity and its future financial condition and results of 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 driven by a number of separate factors, including electric power supply shortages in the Western United States during the first half of the year, weather conditions, gas supply costs and transmission constraints. As a result of these factors, 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. These conditions resulted in the well-publicized "California energy crisis" and in the bankruptcy filings of the California Power Exchange ("Cal PX") and of Pacific Gas & Electric Company ("PG&E"), although the turmoil in the western markets was not limited to California. However, over the last fifteen months, conditions in the western wholesale power market have changed substantially as the result of certain regulatory actions (see below), moderate weather conditions, conservation measures, the construction of additional generation, and a decline in natural gas prices, as well as the lingering slowdown in the regional economy. These changes have placed and are expected to continue to place downward pressure on wholesale electricity prices, with the result that 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. 65 In response to the turmoil in the Western energy market, the FERC initially imposed a "soft" price cap of $150 per MWh for sales to the 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 modified by orders of the FERC 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. Shortly thereafter, 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. This plan replaced the $150 per MWh soft cap previously established and applied during periods of system emergency. Subsequently, the FERC issued still another order that changed the previous orders and expanded the price mitigation approach to the entire western region. In July 2002, the FERC issued further orders to address wholesale power prices in the western market. On July 11, the FERC established a price cap of $91.87 per MWh for the period ending September 30, 2002. On July 17, the FERC entered an order, which was to have taken effect October 1, 2002, raising the price cap to $250 per MWh. However, the FERC extended the $91.87 per MWh price cap through October 31, 2002. Once it becomes effective, the revised price cap can be affected by other factors that could cause the cap to be below $250 per MWh. According to the FERC, this price cap will spur new investment in generation and will foster the eventual return of a robust competitive marketplace. The July 17 order also established mechanisms to prevent power suppliers from engaging in market manipulation activities. As a result of the foregoing conditions in the Western market, the FERC and other federal and state governmental authorities are conducting investigations and other proceedings relevant to the Company and other sellers. The more significant of these in relation to the Company are summarized below. California Refund Proceeding By order dated June 19, 2001, the FERC directed one of its administrative law judges to convene a settlement conference to address potential refunds owed by sellers into the California market. The settlement conference, in which PNM participated, was ultimately unsuccessful, and the administrative law judge recommended to the FERC that an evidentiary hearing be held to resolve the dispute, suggesting that refunds were due; however, the estimated refunds were significantly lower than those 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. Hearings on the refunds were held in September 2002 and the parties will be filing post-hearing positions. A recommended decision is not anticipated until the end of 2002, with a FERC decision by approximately the spring of 2003. The Company is unable to predict the ultimate outcome of this FERC proceeding, or whether PNM will be directed to make any refunds as the result of a FERC order. 66 Pacific Northwest Refund Proceeding In addition to the California refund proceedings, 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 sales into the Pacific Northwest, but the FERC has not yet acted on this recommended decision. The Company is unable to predict the ultimate outcome of this FERC proceeding, or whether PNM will be directed to make any refunds as the result of an order by the FERC. FERC Investigation of "Enron-Like" Trading Practices The FERC has also initiated a market manipulation investigation, partially in response to the bankruptcy filing of the Enron Corporation ("Enron") and to allegations that Enron may have engaged in manipulation of portions of the Western wholesale power market. 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. PNM made its data submission on April 2, 2002. Subsequently, in May 2002, new Enron documents came to light that raised additional concerns about Enron's trading practices. In light of these new revelations, the FERC issued additional orders in the pending investigation requiring sellers to respond to detailed questions by admitting or denying that they had engaged in trading practices similar to those practiced by Enron and certain other sellers, including so-called "wash" transactions. In its responses, PNM denied that it had engaged in improper activities such as those identified in Enron's memos and also denied engaging in "wash" transactions. The Company admitted engaging in certain activities described in the memos that were not improper. Where appropriate, PNM's responses addressed any arguable similarities between any of its trading activities and those under investigation by the FERC. The FERC staff has issued a preliminary report on its findings, recommending that the FERC initiate formal investigative proceedings directed at three companies and the FERC has done so. The Company was not one of these companies named. The Company cannot predict the outcome of this investigation. California Power Exchange and Pacific Gas and Electric Bankruptcies In 2001, approximately $2 million in wholesale power sales by PNM 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 Cal 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. PG&E subsequently also sought bankruptcy protection. PNM has filed its proofs of claims in the Cal PX and PG&E bankruptcy proceedings. Total amounts due PNM 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. PNM was invoiced for $2.3 million as its proportionate share under the Cal PX tariff. PNM, as well as a number of power marketers and generators, filed complaints with the FERC to halt the Cal PX's 67 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. California Attorney General Complaint 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"). PNM was among the sellers identified in this complaint and the Company filed its answer and motion to intervene. In its answer, PNM defended its pricing and challenged the theory of liability underlying the California Attorney General's complaint. On May 31, 2002, the FERC entered an order denying the rate relief requested in the complaint, but directing sellers, including PNM, to comply with additional reporting requirements with regard to certain wholesale power transactions. PNM has made required filings under the May 31 order. The California Attorney General filed a request for rehearing contesting the FERC decision. On September 23, 2002, the FERC issued its order denying the Attorney General's request for rehearing. The California Attorney General has filed a petition for review in the United States Court of Appeals for the Ninth Circuit. As addressed below, the California Attorney General has also threatened litigation against PNM in state court in California based on similar allegations. California Attorney General Threatened Litigation 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 PNM of his intent to file a complaint in California state court against PNM concerning its alleged failure to file rates for wholesale electricity sold in California and for allegedly charging unjust and unreasonable rates in the California markets. The letter invited PNM to contact the California Attorney General's office before the complaint was filed, and PNM has met twice with representatives of the California Attorney General's office. Further discussions are contemplated. To date, a lawsuit has not been filed by the Attorney General and the Company cannot predict the outcome of this matter. California Antitrust Litigation 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 Corporation ("Duke") and related entities along with other named sellers into the California market and numerous other "unidentified defendants." These lawsuits were consolidated for hearing in state court in San Diego. On May 3, 2002, the Duke defendants in the foregoing state court litigation served a cross-claim on PNM. 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. Several defendants have removed the case to federal court and a motion is pending to remand the case back to state court. PNM has joined with other cross-defendants in motions to dismiss the cross-claim. The Company cannot predict the outcome of this matter. 68 Block Forward Agreement Litigation On February 1, 2002, PNM was served with a declaratory relief complaint filed by the State of California in California state court. The state's declaratory relief complaint seeks a determination that the state is not liable for its commandeering of certain energy contracts known as "Block Forward Agreements". The Block Forward Agreements were a form of futures contracts for the purchase of electricity at below-market prices and served as security for payment by PG&E and SCE for their electricity purchases through the Cal PX. When PG&E and SCE defaulted on payment obligations incurred through the Cal PX, the Cal PX moved to liquidate the Block Forward Agreements to satisfy in part the obligations owed by PG&E and SCE. Before the Cal PX could liquidate the Block Forward Agreements, California commandeered them for its own purposes. In March 2001, PNM and other similarly situated sellers of electricity through the Cal PX filed claims for damages with the California state Victims Compensation and Government Claims Board ("Victims Claims Board") on the theory that the state, by commandeering the Block Forward Agreements, had deprived them of security to which they were entitled under the terms of the Cal PX's tariff. The Victims Claims Board filing was an administrative remedy that served as a mandatory prerequisite to filing suit against the state for recovery of damages related to the commandeering of the Block Forward Agreements. The Victims Claims Board denied PNM `s claim on March 22, 2002. PNM filed a complaint against the State of California in California state court on September 20, 2002 seeking damages for the state's commandeering of the Block Forward Agreements and requesting judicial coordination with the state's declaratory relief action filed in February 2002 on the basis that the two actions raise essentially the same issues. On September 27, 2002, the state court granted a six month stay of the proceedings pending resolution of certain related issues before the FERC. Credit Issues As a result of the slowdown in the wholesale electric market and the bankruptcy of a major trader in 2001, a significant number of companies that trade in electricity have experienced liquidity problems, resulting in a downgrade in their credit ratings. This has had the effect of reducing the number of credit worthy companies in the market. Some companies have curtailed their activity or exited the business altogether. The Company's credit risk is monitored by its Risk Management Committee ("RMC"), 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 offsetting positions with its customers. PNM trades with companies of various credit qualities. For those companies who are not investment grade, the Company provides a minimal amount of credit. For companies that are designated as key strategic business partners by the RMC but are not investment grade, the Company attempts to obtain a parental guarantee (if investment grade) or other acceptable collateral. Currently, 71% of trading partners who are not investment grade have such credit enhancements in place. In the current downturn, the Company may be exposed to credit risk if any of its customers experience liquidity problems. 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, PNM began to sell power to the Cal DWR. The Company has regularly monitored its credit risk with regard to the Cal DWR sales and believes its exposure is prudent. 69 In addition to sales directly to California, PNM 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 non-California power sales ultimately are resold in the California market. To the extent these customers who sell power into California are dependent on payment from California to make their payments to PNM, 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 allowance against revenue of $12.0 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. As of December 31, 2001, $8.9 million was transferred to the allowance for bad debt. The Company reduced its reserves by $0.6 million for the nine months ended September 30, 2002 as a result of fewer trades from a lack of liquidity, lower prices and lower volatility. Based on information available at September 30, 2002, the Company believes the total allowance for anticipated losses (exclusive of bad debt), currently established at $2.4 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. TERMINATION OF WESTERN RESOURCES TRANSACTION On November 9, 2000, the Company and Westar Energy, Inc. (formerly known as Western Resources) ("Westar Energy") announced that both companies' boards of directors approved an agreement under which the Company would acquire the Westar Energy electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Westar Energy split-off its non-utility businesses to its shareholders prior to closing. After adverse rulings by the Kansas Corporation Commission regarding the proposed split-off pursuant to the agreement and regarding Westar Energy's electric rates, the transaction was terminated. The Company sued Westar Energy in New York state court for unspecified damages for breach of contract and for declaratory judgment. Westar Energy countersued, claiming entitlement to termination fees in the amount of $25 million, plus costs and fees, and other unspecified damages. On September 25, 2002, the Company and Westar Energy jointly announced that they had settled the litigation with each party dismissing its claims against the other party and each party bearing its own costs. 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, order PNM to provide network transmission service to WAPA under PNM's Open Access Transmission Tariff on behalf of the United States Department of Energy ("DOE") as contracting agent for Kirtland Air Force Base ("KAFB"). 70 In 2001, the FERC issued a "proposed" order directing PNM to provide transmission service, but left the terms of service to be negotiated by the parties and subject to the final review and determination of the FERC. 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 reserved PNM'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 PNM to provide the service. WAPA requested rehearing of the April 12 order approving the settlement, and FERC has issued an order granting rehearing of the April 12 order for the purpose of further consideration. PNM requested rehearing of the April 29 final order. FERC denied WAPA's request for rehearing of FERC's order, ruling in PNM's favor on the question of whether PNM is required to provide credits to the customer's bills with respect to certain facilities funded by the customer. In that same order, the FERC confirmed that PNM's request for rehearing of a separate order had been denied because the FERC did not act on PNM's request within thirty days. The Company filed an appeal of the April 29 order in the United States Court of Appeals for the 10th Circuit. The final briefs will be filed early next year. Oral argument still has not been scheduled. 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 PNM makes to DOE, the effect of the FERC's proposed order to provide transmission service depends upon PNM's ability to sell the power to a different customer and the price that PNM would obtain if it makes such a sale. Depending on market conditions, the Company estimates that the impact of the order will be a loss of revenues of approximately $3 to $6 million. NEW SOURCE REVIEW RULES In November 1999, the Department of Justice at the request of the Environmental Protection Agency (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 New Source Review ("NSR") requirements and in some cases the New Source Performance Standards ("NSPS") regulations, which could result in the requirement to make costly environmental additions to older power plants. Whether or not the EPA will prevail is unclear at this time. The EPA has reached a settlement with one of the companies sued by the Justice Department. Discovery continues in the pending litigation. No complaint has been filed against PNM 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 PNM, advising PNM 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." PNM has responded to the NMED information request. In late June 2002, PNM received another information request from the NMED for a list of capital budget item projects budgeted or completed in 2001 or 2002. PNM has responded to this NMED information request. 71 The National Energy Policy released in May 2001 by the National Energy Policy Development Group called for a review of the pending EPA enforcement actions. As a result of that review, on June 14, 2002 the EPA announced its intention to pursue steps to increase energy efficiency, encourage emissions reductions and make improvements and reforms to the NSR program. The EPA announced that, among other things, the NSR program had impeded or resulted in the cancellation of projects that would maintain or improve reliability, efficiency and safety of existing power plants. However, the EPA's June 2002 announcement contemplates further rulemakings on NSR-related issues and expressly cautions that the announcement is not intended to affect pending NSR enforcement actions. Therefore, the ultimate resolution of NSR-related issues raised by the enforcement actions remains unclear and if the EPA were to prevail in the position advanced in the pending litigation, 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. 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 PNM of GCT's intent to file a so-called "citizen suit" under the Clean Air Act, alleging that PNM and co-owners of the SJGS violated the Clean Air Act, and the implemention of federal and state regulations, at SJGS. Pursuant to that notification, on May 16, 2002, the GCT filed suit in federal district court in New Mexico against PNM (but not against the other SJGS co-owners). The suit alleges two violations of the Clean Air Act and related regulations and permits. First, GCT argues that the plant has violated, and is currently in violation of, the federal Prevention of Significant Deterioration ("PSD") rules, as well as the corresponding provisions of the New Mexico Administrative Code, at SJGS Units 3 and 4. Second, 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 lawsuit seeks penalties as well as injunctive and declaratory relief. PNM filed its answer in federal court on June 6, 2002, denying the material allegations in the complaint. Discovery is on-going. The plaintiffs have filed a motion for partial summary judgment on the opacity issues, to which PNM's response was filed on November 6, 2002. A trial date on liability issues has been scheduled on a trailing docket for June 2003. Based on its investigation to date, the Company firmly believes that the allegations are without merit and vigorously disputes the allegations. PNM has always adhered and continues to adhere to high environmental standards as evidenced by its ISO 14000 certification. The Company is, however, unable to predict the ultimate outcome of the matter. 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 PNM line near the location. The explosion destroyed a small building and injured two persons who were working in the building. PNM's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. PNM also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau (the "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 PNM by the injured persons along with several claims for property and business interruption damages have been resolved. 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. 72 NAVAJO NATION TAX ISSUES APS, the operating agent for Four Corners, 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. On August 15, 2002 PNM entered into a settlement and closing agreement with the Navajo Nation which resolved all tax issues relating to the generating facility but is continuing discussions to resolve tax issues relating to transmission facilities. While the Company cannot predict the outcome of the ongoing settlement discussions, the settlement will not have a material impact on the results of operations and financial position of the Company. LANDOWNER ENVIRONMENTAL CLAIMS In March 2002, a lawsuit was filed in New Mexico state court by a landowner owning property in the vicinity of SJGS, against PNM and SJCC. The lawsuit was served on the defendants on June 11, 2002. 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. PNM has denied the allegations of wrongdoing and is vigorously defending this matter, but is unable to predict the outcome of this matter. ARCHEOLOGICAL SITE DISTURBANCE The Company hired a contractor, Great Southwestern Construction, Inc. ("Great Southwestern"), to conduct certain "climb and tighten" activities on a number of electric transmission lines in New Mexico between July 2001 and December 2001. Those lines traverse a mix of federal, state, tribal and private properties in New Mexico. In late May 2002, the U.S. Forest Service ("USFS") notified PNM that apparent disturbances to archeological sites had been discovered in and around the rights-of-way for PNM's transmission lines in the Carson National Forest in New Mexico. Great Southwestern performed "climb and tighten" activities on those transmission lines. PNM has confirmed the existence of the disturbances, as well as disturbances associated with certain arroyos that may raise issues under section 404 of the Clean Water Act. PNM has given the Corps of Engineers notice concerning the disturbances in arroyos. The Corps of Engineers has acknowledged the Company's notice and asked PNM to cooperate in addressing these disturbances. No formal or written demand by the USFS has been made on the Company with respect to this matter, but the USFS has verbally instructed PNM to undertake an assessment and possible related mitigation measures with respect to the archeological sites in question. PNM has contracted for an archeological assessment and a proposed remediation plan with respect to the disturbances. PNM has provided Great Southwestern with notice and a demand for indemnity. A subsequent preliminary investigation into other transmission lines that were covered by the "climb and tighten" project indicated that there are disturbances on lands governed by other federal agencies and Indian tribes. PNM and Great Southwestern have provided notice of the potential disturbances to these other agencies and tribes. No formal action has been initiated against PNM and no notice of any contemplated action has been received. The Company has been informed that the USFS has commenced a criminal investigation into Great Southwestern's activities on this project. The Company is unable to predict the outcome of this matter and cannot estimate with any certainty the potential impact on the Company's operations. 73 DUGAN PRODUCTION CORPORATION LITIGATION On July 30, 2002, Dugan Production Corp. filed a lawsuit in the County of San Juan, New Mexico, against the SJCC. On September 2, 2002, the SJCC removed the lawsuit to the United States District Court for the District of New Mexico. The lawsuit seeks to enjoin the underground mining of coal from a portion of the land that is to be used for the underground mine. The plaintiff also seeks monetary damages. The SJCC through leases with the federal government and the State of New Mexico, owns coal interests with respect to the underground mine. The plaintiff, through leases with the federal government, the State of New Mexico and certain private parties, claims to own certain oil and gas interests in portions of the land that is to be used for the underground mine. The plaintiff alleges that the defendant's underground coal mining operations have or will interfere with plaintiff's gas production and result in the dissipation of natural gas that it otherwise would be entitled to recover. The plaintiff also alleges, and seeks a declaration by the court, that the rights under its leases are senior and superior to the rights of the SJCC. The SJCC intends to vigorously dispute the litigation. On September 17, 2002, the SJCC filed a motion to dismiss the claims against it on several grounds. Discovery for the lawsuit has not yet started. The Company cannot predict the ultimate outcome of the litigation or whether the litigation will adversely affect the amount of coal available, or the price thereof, for SJGS. EXCESS EMISSIONS REPORTS As required by law, whenever there are excess emissions from SJGS, due to such causes as start-up, shutdown, upset, breakdown or certain other conditions, PNM makes filings with the NMED. For almost two years, PNM has been in discussions with NMED concerning excess emissions reports for the period between January 1997 and July 2002. NMED is still in the process of investigating the circumstances of these excess emissions and whether these emissions involve any violation of applicable permits and regulations. PNM and NMED have entered into several agreements tolling the running of the statute of limitations in order to allow NMED to complete its review of these filings. The present tolling agreement expires December 16, 2002. PNM has been advised by NMED counsel that NMED is in the process of preparing a draft administrative compliance order addressing certain claimed violations, but PNM has not seen this draft order and has not had a chance to meet with NMED to address any violations that might be claimed. The Company is unable to predict the outcome of this matter and cannot estimate the potential impact on the Company's operations. PRC Renewable Resources Rulemakings By Notice of Proposed Rulemaking, dated February 26, 2002, the PRC proposed the adoption of a new Rule 572 to encourage the development of renewable energy in New Mexico. The notice provided for the filing of public comments and scheduled a public hearing for April 23, 2002. After a workshop in which at least 22 entities participated, PRC staff submitted a summary of positions of the parties to the PRC, along with its recommendations. On October 1, 2002, the PRC issued an Amended Notice of Proposed Rulemaking proposing a revised rule. Among other things, new proposed Rule 572 would establish a renewable portfolio standard of 4% by 2004, increasing to 7% by 2007 and 10% by 2010. No more than 50% of a utility's renewable energy resources portfolio would 74 be allowed to be from any single type of renewable resource for purposes of compliance with the portfolio standard. Other new developments on the revised proposed rule include language regarding trading credits, net metering (of renewable energy projects up to 100 kW), the deletion of interconnection requirements (to be addressed in later rulemakings), and rural cooperatives (included under the rule for reporting purposes and for purposes of having a voluntary green pricing tariff, but excluded for purposes of the mandatory renewable portfolio standard). The PRC is in the process of receiving comments and a hearing is scheduled for November 24, 2002. Depending on the outcome of this rulemaking, the makeup of PNM's generation resource portfolio could be significantly different. The Company is unable to predict the outcome of this rulemaking proceeding. Santa Fe Generating Station ("Santa Fe Station") PNM and the NMED conducted investigations of the gasoline and chlorinated solvent groundwater contamination detected beneath PNM's former Santa Fe Station site to determine the source of the contamination pursuant to a 1992 Settlement Agreement ("Settlement Agreement") between PNM and the NMED. No source of groundwater contamination was identified as originating from the site. However, in June 1996, PNM received a letter from the NMED, indicating that the NMED believed PNM is the source of gasoline contamination in a City of Santa Fe municipal supply well and of groundwater underlying the Santa Fe Station site. Further, the NMED letter stated that PNM was required to proceed with interim remediation of the contamination pursuant to the New Mexico Water Quality Control Commission regulations. In October 1996, PNM and the NMED signed an amendment to the Settlement Agreement concerning the groundwater contamination underlying the site. As part of the amendment, PNM agreed to spend approximately $1.2 million for certain costs related to sampling, monitoring and the development and implementation of a remediation plan. The amended Settlement Agreement does not, however, provide PNM with a full release from potential further liability for remediation of the groundwater contamination. After PNM has expended the settlement amount, if the NMED can establish through binding arbitration that the Santa Fe Station is the source of the contamination, PNM could be required to perform further remediation that is determined to be necessary. PNM continues to dispute any contention that the Santa Fe Station is the source of the groundwater contamination and believes that insufficient data exists to identify the sources of groundwater contamination. PNM's aquifer characterization and groundwater quality reports compiled from 1996 through 2000 strongly suggest groundwater contamination has been drawn under the site by the pumping of the Santa Fe supply well. PNM and the NMED, with the cooperation of the City of Santa Fe, jointly selected a 3 to 4 year remediation plan proposed by a remediation contractor. The City of Santa Fe, PNM and the NMED entered into a memorandum of understanding concerning the selected remediation plan and the operation of the municipal well adjacent to the Santa Fe Station site in connection with carrying out the plan. On October 5, 1998, a new system began operation to treat groundwater produced by the Santa Fe well to drinking water standards for municipal distribution and bioremediation of groundwater contamination beneath the Santa Fe Station site. Since the reactivation of the Santa Fe well, the groundwater treatment and bioremediation systems have resulted in a marked reduction in contaminant concentrations at the wellhead. However, contaminant concentrations at the property boundary remain high. 75 By letter dated August 7, 2002, PNM provided written notice to the NMED and the City of Santa Fe that PNM had satisfied its obligations with respect to the gasoline contamination under the amended Settlement Agreement and stated its intention to cease operation, effective October 5, 2002, of the wellhead and bioremediation systems, and to discontinue monitoring and reporting with respect to gasoline contamination at the site. The NMED responded with a written notice of determination dated August 16, 2002 that PNM is the responsible party for gasoline contamination at the site and requested that PNM refrain from cessation of operation of the remediation systems, monitoring and reporting. In a meeting held on September 5, 2002, the NMED indicated its intention to file a court action seeking an order invalidating the binding arbitration provisions of the amended Settlement Agreement and a declaratory judgment that PNM is the responsible party for the gasoline contamination at the site. PNM, the NMED and the City of Santa Fe have tentatively agreed to refrain from filing any actions or invoking the dispute resolution provisions under the Settlement Agreement pending further data review and negotiation with respect to the NMED's determination. PNM has tentatively agreed to continue operation of the wellhead treatment system at the site and to continue well monitoring and reporting to the NMED through October 5, 2003. The Company cannot predict the outcome of these negotiations with NMED. 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 results from the acquisition, construction or development 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 financial condition and results of operations. 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 or financial condition and results of operations. 76 Statement of Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections" ("SFAS 145"). In April 2002, the FASB issued SFAS 145. This statement updates and clarifies existing accounting pronouncements for treatment of gains and losses from extinguishment of debt and eliminates an inconsistency between required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have similar economic effects as sale-leaseback transactions. In accordance with previous accounting standards, gains and losses from extinguishment of debt were classified as extraordinary gains and losses. The current statement permits gains and losses from extinguishment of debt to be classified as ordinary and included in income from operations, unless they are unusual in nature or occur infrequently and therefore included as an extraordinary item. Emerging Issues Task Force ("EITF") Issue 02-3 "Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities", EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and Statement of Financial Accounting Standards No. 133 ("SFAS 133") "Accounting for Derivative Instruments and Hedging Activities". The Company evaluates its energy contracts to determine if they meet the definition of a derivative and are therefore subject to the accounting requirements of SFAS 133. If an energy contract is determined not to be a derivative under SFAS 133, it is then evaluated under EITF 98-10 to determine whether it meets the definition of a trading activity and should be marked to market with gains and losses recognized in earnings and separately disclosed in the financial statements. EITF 98-10 allowed a gross or net presentation of these gains and losses in the statement of earnings. In June 2002, the EITF reached a consensus in EITF 02-3 that all energy trading activities must be presented on a net margin basis rather than a gross basis in the statement of earnings and further required that all prior periods be reclassified to conform to the current period presentation. On October 25, 2002, the EITF reached a consensus to rescind EITF 98-10 and will no longer allow energy contracts that do not meet the definition of a derivative under SFAS 133 to be marked to market and recognized in current earnings. As a result, all contracts which were marked to market under EITF 98-10 and must now be accounted for under the accrual method will be written back to cost with any difference included as a cumulative effect adjustment in the period of adoption. This transition provision will be effective for the first quarter of 2003. The disclosure provisions previously agreed to in EITF 02-3 have also been rescinded. In addition, any contracts within Statement 133 that are trading or held for trading and are settled physically should be reported on a net basis. Any contracts within Statement 133 that are not considered trading and are settled physically should be reported on a gross basis. The EITF has directed the FASB staff to provide a definition of trading activities to be included in the final written consensus of EITF 02-3. The decision to rescind EITF 98-10, the uncertainty as to the ultimate definition of trading activities and the October 2002 consensus as to the effective date for adoption of EITF 02-3 has nullified the June 2002 consensus on net margin versus gross basis presentation. Therefore, the Company has not reclassified its energy trading activities to a net margin presentation as of September 30, 2002 and is currently assessing the impact of the EITF's October consensus on the accounting for its energy contract portfolio. The Company expects to adopt EITF 02-3 in its entirety in the first quarter of 2003. 77 The SEC has indicated that financial statement reclassifications related to periods previously audited by Arthur Andersen LLP ("Arthur Andersen") may require the successor auditor to audit the prior periods and issue a new audit report. Arthur Andersen audited the Company's financial statements for the fiscal years 2001 and 2000. The successor auditor, Deloitte and Touche, has not issued a new review report for the three and nine months ended September 30, 2001. However, Deloitte and Touche will perform an audit of the Companies' financial statements for fiscal year 2001. 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 performance of generating units and transmission system, the transition to the underground mine for the supply of coal to SJGS, the creditworthiness of the Company's marketing and trading counterparties, 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, rulings issued by the PRC pursuant to the Electric Utility Industry Restructuring Act of 1999, as amended, on the recently filed agreement regarding merchant plant and a five year rate path, 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. 78 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. 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 Holding Company Board of Directors. The Board's Finance Committee 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 unit's 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. 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. 79 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. PNM 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 PNM's aggregate net open position is covered by its own excess generation capabilities. PNM is exposed to market risk if its generation capabilities were disrupted or if its retail load requirements were greater than anticipated. If PNM 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 PNM'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 electric generation in excess of its retail needs or the purchase of power for retail needs as non-trading. Purchases for resale and subsequent resales are accounted for as energy trading contracts. With respect to PNM's trading portfolio, the VAR was $34.1 thousand at September 30, 2002. The Company calculates a portfolio VAR, which in addition to its trading portfolio includes all non-trading designated contracts, its generation assets excluded from retail rates and any capacity in excess of retail needs. This excess is determined using average peak forecasts for the respective block of power in the forward market. The Company's portfolio VAR was $3.9 million at September 30, 2002. 80 The following table shows the high, average and low market risk as measured by VAR on the Company's trading portfolio: Nine Months Ended September 30, 2002 -------------------------------------- High Average Low ---------- ----------- --------- (In thousands) $1,298 $584 $34 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 PNM'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 PNM's wholesale power marketing portfolio during the year. In addition, PNM is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to assess and monitor the financial conditions of counterparties. Credit exposure is also regularly monitored by the RMC. The Company provides for losses due to market and credit risk. PNM's credit risk with its largest counterparty as of September 30, 2002 was $3.9 million. (Intentionally left blank) 81 The following table provides information related to PNM's credit exposure, net of collateral as of September 30, 2002. It further delineates that exposure by the credit worthiness (credit rating) of the counterparties and provides guidance as to the concentration of credit risk to individual counterparties PNM may have. Schedule of Credit Risk Exposure on Mark-To-Market Energy Contracts Net Assets September 30, 2002
Exposure Net Before Number of Exposure of Credit Credit Counter- Counter- Collateral Collateral parties parties Rating (a) 1(b) (c) Net Exposure >10% >10% ------------------------- ------------ ------------- -------------- --------- ------------ (In thousands) Investment grade......... $14,744 $ - $14,744 1 $3,878 Non-investment grade - - - - Split rating............. 4,052 - 4,052 1 3,630 Internal ratings Investment grade...... 1,101 - 1,101 - Non-investment grade............... 13,074 3,543 9,531 - ------------ ------------- -------------- ------------ Total............ $32,971 $3,543 $29,428 $7,508 ============ ============= ============== ============ Credit reserves $2,433 ==============
(a) Rating - Included in "Investment Grade" are counterparties with a minimum Standard & Poor's rating of BBB- or Moody's rating of Baa3. If the counterparty has provided a guarantee by a higher rated entity (e.g., its parent), determination is based on the rating of its guarantor. The "Internal Rated - Investment Grade" includes those counterparties that are internally rated as investment grade in accordance with the guidelines established in the Company's credit policy. (b) The Exposure Before Credit Collateral is the net credit exposure to PNM from its wholesale trading activities. This includes trading contracts, forward physical contracts, and firm off-system contracts. The exposure captures the net amounts due to PNM from receivables/payables for realized transactions, delivered and unbilled revenues, and mark-to-market gains/losses (pursuant to contract terms). Exposures are offset according to legally enforceable netting arrangements. Amounts are presented before those reserves that are determined on a portfolio basis. (See Western United States Wholesale Power Market in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations for discussion of the reserves.) (c) The Credit Collateral reflects the face amount of cash deposits, letters of credit, and performance bonds received from counterparties. PNM hedges certain portions of natural gas supply contracts in order to protect its retail 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 purchased gas adjustment clause. As a result, earnings are not affected by gains and losses generated by these instruments. 82 Interest Rate Risk As of September 30, 2002, the Company has an investment portfolio of fixed-rate government obligations and corporate securities, which were 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 September 30, 2002, the fair value of these instruments would decline by 0.7% or $0.8 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 and obligors and limits credit exposure to high investment grade quality investments. PNM 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 4.15% or $40.0 million if interest rates were to decline by 50 basis points from their levels at September 30, 2002. As of September 30, 2002, the fair value of PNM's long-term debt was $963.6 million as compared to a book-value of $953.9 million. In general, an increase in fair value would impact earnings and cash flows if PNM were to re-acquire all or a portion of its debt instruments in the open market prior to their maturity. Certain issuances of the debt have call dates in December 2002 and August 2003. To hedge against the risk of rising interest rates and their impact on the economics of calling the debt, PNM has entered into forward starting interest rate swaps in 2001 and 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 4.95% plus an adjustment for PNM's and industry's credit rating. At September 30, 2002, the fair market value of these derivative financial instruments was approximately $20.3 million unfavorable to the Company. PNM contributed $6.1 million in 2001 to a trust established to fund decommissioning costs for PVNGS. In January 2002, PNM contributed $23.5 million for plan year 2001 to the trust for the Company's pension plan, and other post retirement benefits. Additional contributions of $1.1 million were made in September 2002 for the 2002 plan year. The securities held by the trusts had an estimated fair value of $423 million as of September 30, 2002, of which approximately 32% 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 September 30, 2002, the decrease in the fair value of the securities would be 3.1% or $4.2 million. PNM 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. 83 Equity Market Risk As discussed above under Interest Rate Risk, PNM contributes to trusts established to fund its share of the decommissioning costs of PVNGS and pension and other postretirement benefits. The trust holds certain equity securities as of September 30, 2002. These equity securities also expose the Company to losses in fair value. Approximately 60% of the securities held by the various trusts were equity securities as of September 30, 2002. Similar to the debt securities held for funding decommissioning and certain pension and other postretirement costs, PNM 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 & Poor's 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 has VAR and stop loss limits established. Trades are typically closed-out before the end of a reporting period and within the same day of execution. The VAR at September 30, 2002 was $44 thousand, utilizing a one-day, two-tailed, 99% confidence interval. Recently, the RMC recommended and the Finance Committee approved the use of derivatives based on the Nasdaq composite index. Financial Instruments Under the derivative accounting rules and the related accounting rules for energy trading activities, the Company accounts for its various financial derivative instruments for the purchase and sale of energy differently based on management's intent when entering into the contract. Energy trading contracts are recorded at fair market value at each period end. The changes in fair market value are recognized in earnings. Non-trading contracts must be accounted for as derivatives and recorded in the balance sheet as either an asset or liability measured at their fair value. Changes in the derivatives' fair value are recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Should an energy transaction qualify as a hedge, fair market value changes from period to period are recognized on the balance sheet with a corresponding charge to other comprehensive income. Gains or losses are recognized when the hedged transaction occurs. Normal purchases and sales are not marked-to-market but rather recorded in results of operations when the underlying transaction occurs. 84 The following table shows how the net fair value of energy trading contracts was derived from the amounts included in the balance sheet:
September 30, December 31, 2002 2001 ------------ ------------- (In thousands) Energy Trading and Derivative Contracts: Current asset....................................... $ 4,165 $ 9,461 Long-term asset..................................... 393 1,470 ------------ ------------- Total mark-to-market assets...................... 4,558 10,930 ------------ ------------- Current liability................................... (11,975) (36,256) Long-term liability................................. (915) (5,115) ------------ ------------- Total mark-to-market liabilities................. (12,890) (41,370) ------------ ------------- Net fair value of energy trading contracts and related derivatives................................. $ (8,333) $ (30,440) ============ =============
The trading portfolio positions at September 30, 2002 and December 31, 2001 represent net liabilities after netting all open purchase and sale contracts. Because the contractual amounts required to settle the net liability were greater than the current market values of the contracts, the Company recognized mark-to-market losses for the differences in 2002 and 2001. The market prices used to value PNM's energy trading contracts are based on closing exchange prices and over-the-counter quotations. As of September 30, 2002 and December 31, 2001, PNM did not have any outstanding contracts that were valued using methods other than quoted prices. The Company did not change its methods for valuing its trading contracts in 2002 as compared to 2001. The following table provides detail of changes in the Company's mark-to-market net asset or liability balance sheet position from one period to the next. Nine Months Ended September 30, 2002 2001 ------------- -------------- (In thousands) Sources of Fair Value Gain/(Loss) Fair value at beginning of year.............. $(30,440) $ (4,643) Amount realized on contracts delivered during period............................. 19,903 2,736 Changes in fair value........................ 2,204 (29,520) ------------- -------------- Net fair value at end of period.............. $ (8,333) $(31,427) ============= ============== Net change recorded as mark-to-market........ $22,107 $(26,784) ============= ============== 85 This table provides the maturity of the net assets/liabilities of the Company, giving an indication of when these mark-to-market amounts will settle and generate cash. Fair Value of Contracts at September 30, 2002 Maturities ----------------------------------------------- Less than Sources of Fair Value 1 year 1-3 Years Total ------------------------- ------------- ------------- -------------- (In thousands) Trading.................. $(7,811) $ (522) $ (8,333) Note: All values determined using broker quotes. As of September 30, 2002, a decrease in market pricing of PNM's trading contracts by 10% would have resulted in a decrease in net earnings of less than 1%. Conversely, an increase in market pricing of the trading contracts by 10% would have resulted in an increase in net earnings of less than 1%. At September 30, 2002, the market value of PNM's normal sales and purchases of electricity was a $20.7 million asset using the valuation methods described above. If these transactions were classified as trading or did not meet the definition of normal under the accounting rules for derivatives, the Company would have recognized unrealized gains of $22.4 million as an adjustment to Generation and Trading operating revenues based on the change in fair value of these contracts from January 1, 2002 to September 30, 2002. In addition to the fair market valuation described above, the Company provides for losses due to market and credit risk in the electric wholesale marketplace based on its assessment of counterparty default risk. This assessment is based on a methodology that considers the credit ratings of counterparties, the price volatility in the marketplace, the fair market value of all contracts outstanding and management's evaluation of market trends that are expected to impact market risk. The resulting amount is recorded as an adjustment to revenue. As a result of fewer trades from a lack of liquidity, lower prices and lower volatility, the Company recognized an increase in revenues of $0.6 million for the nine months ended September 30, 2002. ITEM 4. CONTROLS AND PROCEDURES (a) Evaluation of disclosure controls and procedures. The Company's principal executive officer and principal financial officer have concluded that the Company's disclosure controls and procedures, based on their evaluation on October 9, 2002 of these disclosure controls and procedures, are effective to ensure that material information relating to the Company, including its consolidated subsidiaries, was made known to them by others within those entities, particularly during the period in which the periodic reports are being prepared. (b) Changes in internal controls. None. 86 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 2001 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. 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 PNM 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. 87 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, the EPA and other parties have requested that the Court stay any further briefing while they negotiate a settlement. 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, PNM was informed that the DOE had entered into an agency agreement with WAPA on behalf of KAFB, one of PNM'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, PNM 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 PNM's transmission system. PNM 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. PNM 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 PNM to provide network transmission service to WAPA on behalf of DOE and several other entities located on KAFB under PNM'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, the FERC granted WAPA's request for rehearing. The FERC determined that WAPA qualified for an exemption to the prohibition against an order requiring service to retail customers and that the FERC therefore could require PNM to provide the requested service. The FERC directed PNM 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 the 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 the FERC reserved PNM'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 PNM to provide service. WAPA requested rehearing of the April 12 order 88 approving the settlement, and the FERC issued an order granting rehearing for further consideration. PNM requested rehearing of the April 29 final order directing PNM to provide service. The FERC denied WAPA's request for rehearing of the FERC's order, ruling in PNM's favor on the question of whether PNM is required to provide credits to the customer's bills with respect to certain facilities funded by the customer. In that same order, the FERC confirmed that PNM's request for rehearing of a separate order had been denied because the FERC did not act on PNM's request within thirty days. The Company filed a petition for review of the FERC Final Order in the United States Court of Appeals for the Tenth Circuit. The Company, USEA and WAPA have entered a binding memorandum of understanding potentially resolving the dispute. The memorandum provides that, if the agreement currently before the PRC resolving the Company's electric rate path and merchant plant issues described earlier in (wherever it is described) is approved by the PRC and becomes effective, the Company will dismiss its appeal at the Tenth Circuit and WAPA will purchase from the Company approximately 60 MW of electric power that will be wheeled under the FERC Final Order to serve KAFB. The power sales agreement between WAPA and the Company will last at least 6 years. The parties to the memorandum have agreed that the appeal proceedings in the Tenth Circuit will be suspended until the outcome of the PRC proceeding is known and service commences under the power sales agreement. If the outcome is not known by March 20, 2003, the memorandum provisions concerning dismissal of the appeal and the power sales agreement can be voided. Should the memorandum provisions become void and should DOE on behalf of KAFB choose to use WAPA for purchase and transmission 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. Depending on market conditions, the Company estimates that the impact of the order will be a loss of revenues of approximately $3 to $6 million. In a separate but related proceeding, PNM 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 PNM provides retail service to KAFB. PNM 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. 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, agreeing that the City would offer employment to the water utility employees when this agreement expired. This 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. 89 In July 2001, the Maintenance and Operations Agreement ended, and most of the water operations employees accepted employment with the City. However, on March 27, 2001, the IBEW filed a 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 arbitrated the dispute in May 2002 and on July 24, 2002, the arbitrator issued a written decision in favor of the Company denying the grievance. WESTAR ENERGY On November 9, 2000, the Company and Westar Energy announced that both companies' boards of directors approved an agreement under which the Company would acquire the Westar Energy electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Westar Energy split-off its non-utility businesses to its shareholders prior to closing. After adverse rulings by the Kansas Corporation Commission regarding the proposed split-off pursuant to the agreement and regarding Westar Energy's electric rates, the transaction was terminated. The Company sued Westar Energy in New York state court for unspecified damages for breach of contract and for declaratory judgment. Westar Energy countersued, claiming entitlement to termination fees in the amount of $25 million, plus costs and fees, and other unspecified damages. On September 25, 2002, the Company and Westar Energy jointly announced that they had settled the litigation between them, with each party dismissing its claims against the other party and each party bearing its own costs. California Attorney General Complaint 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 Cal DWR. PNM was among the sellers identified in this complaint and filed its answer and motion to intervene. In its answer, PNM defended its pricing and challenged the theory of liability underlying the California Attorney General's complaint. On May 31, 2002, the FERC entered an order denying the rate relief requested in the complaint, but directing sellers, including PNM, to comply with additional reporting requirements with regard to certain wholesale power transactions. PNM has made required filings under the May 31 order. The California Attorney General filed a request for rehearing contesting the FERC's decision. On September 23, 2002, the FERC issued its order denying the California Attorney General's request for rehearing. California Antitrust Litigation 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 and related entities along with other named sellers into the California market and numerous other "unidentified defendants." These lawsuits were consolidated for hearing in state court in San Diego. On May 3, 2002, the Duke defendants in the foregoing state court 90 litigation served a cross-claim on PNM and 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. Several defendants have removed the case to federal court and a motion is pending to remand the case to state court. PNM has joined with other cross-defendants in motions to dismiss the cross-claim. The Company cannot predict the outcome of this matter. Citizen Suit Under the Clean Air Act By letter dated January 9, 2002, counsel for the GCT notified the Company of GCT's intent to file a so-called "citizen suit" under the Clean Air Act, alleging that PNM and co-owners of the SJGS violated the Clean Air Act, and the implemention of federal and state regulations, at SJGS. Pursuant to that notification, on May 16, 2002, the GCT filed suit in federal district court in New Mexico against PNM (but not against the other SJGS co-owners). The suit alleges two violations of the Clean Air Act and related regulations and permits. First, 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 SJGS Units 3 and 4. Second, 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 lawsuit seeks penalties as well as injunctive and declaratory relief. PNM filed its answer in federal court on June 6, 2002, denying the material allegations in the complaint. Discovery is on-going. The plaintiffs have filed a motion for partial summary judgment on the opacity issues, to which the Company's response was filed on November 6, 2002. A trial date on liability issues has been scheduled on a trailing docket for June 2003. Based on its investigation to date, PNM believes that the allegations are without merit and vigorously disputes the allegations. PNM has always adhered and continues to adhere to high environmental standards as evidenced by its ISO 14000 certification. The Company is, however, unable to predict the ultimate outcome of the matter. LANDOWNER ENVIRONMENTAL CLAIMS In March 2002, a lawsuit was filed in the eleventh judicial district of the state of New Mexico by a landowner, owning property in the vicinity of SJGS, against PNM and the SJCC. The lawsuit was served on the defendants on June 11, 2002. 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. PNM has denied the allegations of wrongdoing and is vigorously defending this matter, but is unable to predict the outcome of this matter. 91 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits: 10.74.5 Fifth Amendment to the Third Restated and Amended PNM Resources, Inc. Performance Stock Plan (formerly, the Public Service Company of New Mexico Performance Stock Plan) 15.1 Letter Re: Unaudited Interim Financial Information for PNM Resources, Inc. and Subsidiaries. 15.2 Letter Re: Unaudited Interim Financial Information for Public Service Company of New Mexico. 99.1 Chief Executive Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 Chief Financial Officer Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. b. Reports on Form 8-K: Report dated and filed August 14, 2002 reporting the Company, Pursuant to the order issued by the Securities Exchange Commission ("SEC") on June 27, 2002, Jeffry E. Sterba, Chairman, Chief Executive Officer and President of PNM Resources, Inc. (the Company) and Max H. Maerki, Senior Vice President and Chief Financial Officer of the Company, filed their sworn statements regarding facts and circumstances relating to exchange act filings with the SEC on August 14, 2002. Report dated and filed August 19, 2002 reporting the Company's Comparative Operating Statistics for the month of July 2002 and 2001 and the year ended July 2002 and 2001. Report dated and filed August 23, 2002 reporting the Company Realigns to Capture Efficiencies and Respond to Declining Wholesale Market, Work Force Reduced and Chief Operating Officer Named. Report dated and filed September 13, 2002 reporting the Company's Comparative Operating Statistics for the month of August 2002 and 2001 and the year ended August 2002 and 2001. Report dated and filed September 18, 2002 reporting the Company's Response to the Federal Energy Regulatory Commission's ("FERC") request for information pertaining to the Company's FERC Form 1 for the years 2000 and 2001. Report dated and filed September 26, 2002 reporting the Company and Westar Energy Drop Lawsuit. Report dated and filed September 27, 2002 reporting the Company Declares Preferred Dividends. Report dated and filed October 4, 2002 reporting the Company Declares Common Stock Dividend. Report dated and filed October 11, 2002 reporting the Company Announces to set five-year rate path and projected cost savings will offset lower rates. 92 Report dated and filed October 15, 2002 reporting the Company's Comparative Operating Statistics for the month of September 2002 and 2001 and the year ended September 2002 and 2001. Report dated and filed October 22, 2002 reporting the Company has entered into an agreement with FPL Energy LLC, a subsidiary of FPL Group, Inc. to develop a 200 megawatt wind generation facility in New Mexico. Report dated and filed October 30, 2002 reporting the Company's quarter ended September 30, 2002 Earnings Announcement, Consolidated Statement of Earnings, Consolidated Balance Sheets, Consolidated Statement of Cash Flow and Comparative Operating Statistics. 93 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 --------------------------------------------- (Registrant) Date: November 12, 2002 /s/ John R. Loyack --------------------------------------------- John R. Loyack Vice President and Chief Accounting Officer (Officer duly authorized to sign this report) 94 CERTIFICATIONS: I, Jeffry E. Sterba, certify that: 1. I have reviewed this quarterly report on Form 10-Q of PNM Resources, Inc. and Public Service Company of New Mexico; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 95 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 12, 2002 /s/ Jeffry E. Sterba ---------------------------------- Jeffry E. Sterba, Chairman, President and Chief Executive Officer 96 I, Max H. Maerki, certify that: 1. I have reviewed this quarterly report on Form 10-Q of PNM Resources, Inc. and Public Service Company of New Mexico; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 97 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 12, 2002 /s/ Max H. Maerki ---------------------------------- Max H. Maerki, Senior Vice President and Chief Financial Officer 98