-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IBcFmEJYyepPWE5qn0QZDdvCiRbDE2jujy5EU69aFj4NObaAiLln9nqD2fuLzEmQ /LZwkXoDzWlEPBpOOwgurA== 0000081023-01-500093.txt : 20020410 0000081023-01-500093.hdr.sgml : 20020410 ACCESSION NUMBER: 0000081023-01-500093 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20010930 FILED AS OF DATE: 20011114 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF NEW MEXICO CENTRAL INDEX KEY: 0000081023 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 850019030 STATE OF INCORPORATION: NM FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-06986 FILM NUMBER: 1790933 BUSINESS ADDRESS: STREET 1: ALVARADO SQUARE, MS2706 CITY: ALBUQUERQUE STATE: NM ZIP: 87158 BUSINESS PHONE: 5058482700 10-Q 1 f10q_09302001.txt TEXT TO 10-Q 9-30-2001 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITES EXCHANGE ACT OF 1934 For the period ended September 30, 2001 ------------------ - OR - [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _________________ Commission file number 1-6986 ------ PUBLIC SERVICE COMPANY OF NEW MEXICO ------------------------------------ (Exact name of registrant as specified in its charter) New Mexico 85-0019030 ---------- ---------- (State or other jurisdiction of (I.R.S. Employer Incorporation of organization) Identification No.) Alvarado Square, Albuquerque, New Mexico 87158 ---------------------------------------------- (Address of principal executive offices) (Zip Code) (505) 241-2700 -------------- (Registrant's telephone number, including area code) ------------------------------ Former name, former address and former fiscal year,if changed since last report) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- APPLICABLE ONLY TO CORPORATE ISSUERS: Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock-$5.00 par value 39,117,799 shares ---------------------------- ----------------- Class Outstanding at November 1, 2001 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES INDEX Page No. PART I. FINANCIAL INFORMATION: Report of Independent Public Accountants........................... 3 ITEM 1. FINANCIAL STATEMENTS Consolidated Statements of Earnings - Three Months and Nine Months Ended September 30 2001 and 2000...... 4 Consolidated Balance Sheets - September 30, 2001 and December 31, 2000........................... 5 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2001 and 2000...................... 7 Notes to Consolidated Financial Statements......................... 8 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS............. 27 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK............................................... 67 PART II. OTHER INFORMATION: ITEM 1. LEGAL PROCEEDINGS............................................ 68 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K............................. 73 Signature .......................................................... 75 2 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of Public Service Company of New Mexico: We have reviewed the accompanying condensed consolidated balance sheet of PUBLIC SERVICE COMPANY OF NEW MEXICO (a New Mexico corporation) and subsidiaries as of September 30, 2001, and the related condensed consolidated statements of earnings 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 3 ITEM 1. FINANCIAL STATEMENTS PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS (Unaudited)
Three Months Ended Nine Months Ended September 30, September 30, ------------------------- ------------------------ 2001 2000 2001 2000 ----------- ------------ ---------- ------------- (thousands, except per share amounts) Operating Revenues: Electric......................................... $ 582,066 $ 444,101 $ 1,704,390 $ 943,681 Gas.............................................. 39,649 55,133 318,670 204,193 Unregulated businesses........................... 180 243 1,456 1,935 ----------- ----------- ----------- ----------- Total operating revenues....................... 621,895 499,477 2,024,516 1,149,809 ----------- ----------- ----------- ----------- Operating Expenses: Cost of energy sold.............................. 429,965 316,519 1,360,904 664,636 Energy production costs.......................... 36,224 32,854 109,128 104,402 Administrative and general....................... 39,241 36,926 117,494 102,683 Depreciation and amortization.................... 24,194 23,022 72,343 69,664 Transmission and distribution costs.............. 18,402 14,537 48,760 44,614 Taxes, other than income taxes................... 6,380 9,103 21,436 25,234 Income taxes..................................... 20,067 19,064 89,182 32,523 ----------- ------------- ------------ ------------ Total operating expenses..................... 574,473 452,025 1,819,247 1,043,756 ----------- ------------- ------------ ------------ Operating income............................... 47,422 47,452 205,269 106,053 ----------- ------------- ------------ ------------ Other Income and Deductions: Other............................................ 3,310 26,302 (14,196) 49,487 Income taxes..................................... (2,277) (10,733) 3,275 (19,660) ----------- ------------- ------------ ------------ Net other income and deductions................ 1,033 15,569 (10,921) 29,827 ----------- ------------- ------------ ------------ Income before interest charges................. 48,455 63,021 194,348 135,880 ----------- ------------- ------------ ------------ Interest Charges: Interest on long-term debt....................... 15,683 15,683 47,049 47,140 Other interest charges........................... (3) 425 1,375 1,889 ----------- ------------- ------------ ------------ Interest charges............................... 15,680 16,108 48,424 49,029 ----------- ------------- ------------ ------------ Net Earnings....................................... 32,775 46,913 145,924 86,851 Preferred Stock Dividend Requirements.............. 147 147 440 440 ----------- ------------- ------------ ------------ Net Earnings Applicable to Common Stock............ $ 32,628 $ 46,766 $ 145,484 $ 86,411 =========== ============= ============ ============ Net Earnings per Common Share: Basic............................................ $ 0.83 $ 1.19 $ 3.72 $ 2.18 =========== ============= ============ ============ Diluted.......................................... $ 0.82 $ 1.18 $ 3.66 $ 2.17 =========== ============= ============ ============ Dividends Paid per Share of Common Stock........... $ 0.20 $ 0.20 $ 0.60 $ 0.60 =========== ============= ============ ============
The accompanying notes are an integral part of these financial statements. 4
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS September 30, December 31, 2001 2000 -------------- -------------- Unaudited) ASSETS (In thousands) - ------ Utility Plant: Electric plant in service......................................... $2,093,176 $2,030,813 Gas plant in service.............................................. 562,554 553,755 Common plant in service and plant held for future use............. 37,655 36,678 -------------- -------------- 2,693,385 2,621,246 Less accumulated depreciation and amortization.................... 1,237,238 1,153,377 -------------- -------------- 1,456,147 1,467,869 Construction work and progress.................................... 231,128 123,653 Nuclear fuel, net of accumulated amortization of $21,246 and $19,081............................................ 25,303 25,784 -------------- -------------- Net utility plant............................................... 1,712,578 1,617,306 -------------- -------------- Other Property and Investments: Other investments................................................. 439,022 479,821 Non-utility property, net of accumulated depreciation of $1,538 and $1,644............................................. 1,826 3,666 -------------- -------------- Total other property and investments............................ 440,848 483,487 -------------- -------------- Current Assets: Cash and cash equivalents......................................... 222,605 107,691 Accounts receivables, net of allowance for uncollectible accounts of $8,317 and $8,963................................. 262,238 242,742 Other receivables................................................. 44,963 64,857 Inventories....................................................... 38,750 36,091 Regulatory assets................................................. 1,381 47,604 Other current assets.............................................. 48,018 11,417 -------------- -------------- Total current assets............................................ 617,955 510,402 -------------- -------------- Deferred Charges: Regulatory assets................................................. 207,673 226,849 Prepaid benefit costs............................................. 22,948 18,116 Other deferred charges............................................ 20,554 38,073 -------------- -------------- Total deferred charges.......................................... 251,175 283,038 -------------- -------------- $3,022,556 $2,894,233 ============== ==============
5
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS September 30, December 31, 2001 2000 -------------- -------------- Unaudited) CAPITALIZATION AND OTHER LIABILITIES (In thousands) - ------------------------------------ Capitalization: Common stockholders' equity: Common stock......................................................... $ 195,589 $ 195,589 Additional paid-in capital........................................... 428,660 432,222 Accumulated other comprehensive income, net of tax................... (2,986) (27) Retained earnings.................................................... 418,850 296,843 -------------- -------------- Total common stockholders' equity................................. 1,040,113 924,627 Minority interest....................................................... 11,651 12,211 Cumulative preferred stock without mandatory redemption requirements............................................ 12,800 12,800 Long-term debt, less current maturities................................. 953,870 953,823 -------------- -------------- Total capitalization.............................................. 2,018,434 1,903,461 -------------- -------------- urrent Liabilities: Accounts payable........................................................ 206,277 257,991 Accrued interest and taxes.............................................. 116,066 36,889 Other current liabilities............................................... 113,262 67,758 -------------- -------------- Total current liabilities......................................... 435,605 362,638 -------------- -------------- Deferred Credits: Accumulated deferred income taxes......................................... 113,981 166,249 Accumulated deferred investment tax credits............................... 45,499 47,853 Regulatory liabilities.................................................... 56,762 65,552 Regulatory liabilities related to accumulated deferred income tax......... 14,144 20,696 Accrued postretirement benefit costs...................................... 22,226 11,899 Other deferred credits.................................................... 315,905 315,885 -------------- -------------- Total deferred credits................................................. 568,517 628,134 -------------- -------------- $3,022,556 $2,894,233 ============== ==============
The accompanying notes are an integral part of these financial statements. 6
PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) Nine Months Ended September 30, ------------------------------ 2001 2000 ------------- ------------- (In thousands) Cash Flows From Operating Activities: Net earnings....................................................... $ 145,924 $ 86,851 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization.................................. 80,086 77,728 Other, net..................................................... 15,413 (13,031) Changes in certain assets and liabilities: Accounts receivables......................................... (19,497) (69,350) Other assets................................................. 36,490 40,416 Accounts payable............................................. (51,714) 20,997 Accrued taxes................................................ 80,907 23,768 Other liabilities............................................ 9,251 2,884 ------------- ------------- Net cash flows provided from operating activities............ 296,860 170,263 ------------- ------------- Cash Flows From Investing Activities: Utility plant additions............................................ (165,127) (97,738) Return on PVNGS lease obligation bonds............................. 16,674 16,668 Other investing.................................................... (5,440) (5,006) ------------- ------------- Net cash flows used from investing activities................ (153,893) (86,076) ------------- ------------- Cash Flows From Financing Activities: Repayments......................................................... - (32,800) Common stock repurchase............................................ - (27,875) Exercise of employee stock options................................. (3,589) (4) Dividends paid..................................................... (23,905) (24,275) Other financing.................................................... (559) (559) ------------- ------------- Net cash flows used in financing activities.................. (28,053) (85,513) ------------- ------------- Increase in Cash and Cash Equivalents................................ 114,914 (1,326) Beginning of Period.................................................. 107,691 120,399 ------------- ------------- End of Period........................................................ $222,605 $119,073 ============= ============= Supplemental Cash Flow Disclosures: Interest paid...................................................... $ 48,298 $ 50,393 ============= ============= Income taxes paid, net ............................................ $ 56,150 $ 25,922 ============= =============
The accompanying notes are an integral part of these financial statements. 7 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) Accounting Policies and Responsibilities for Financial Statements In the opinion of management of Public Service Company of New Mexico (the "Company"), the accompanying interim consolidated financial statements present fairly the Company's financial position at September 30, 2001 and December 31, 2000, the consolidated results of its operations for the three months and nine months ended September 30, 2001 and 2000 and the consolidated statements of cash flows for the nine months ended September 30, 2001 and 2000. These statements are presented in accordance with the rules and regulations of the United States Securities and Exchange Commission ("SEC"). Accordingly, they are unaudited, and certain information and footnote disclosures normally included in the Company's annual consolidated financial statements have been condensed or omitted, as permitted under the applicable rules and regulations. Readers of these statements should refer to the Company's audited consolidated financial statements and notes thereto for the year ended December 31, 2000, which are included on the Company's Annual Report on Form 10-K for the year ended December 31, 2000. The results of operations presented in the accompanying financial statements are not necessarily representative of operations for an entire year. Certain amounts in the 2000 consolidated financial statements and notes have been reclassified to conform to the 2001 financial statement presentation. (2) Nature of Business and Segment Information The Company is an investor-owned integrated utility engaged in the generation, transmission, distribution and sale and trading of electricity, and the transportation, distribution and sale of natural gas. The Company's principal business segments are Utility Operations, which include the Electric Product Offering ("Electric") and the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations ("Generation and Trading"). 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. Electric procures all of its electric power needs from the Company's Generation and Trading Operations. These intersegment sales are priced using internally developed transfer pricing, and are not based on market rates. Customer electric rates are regulated by the New Mexico Public Regulation Commission ("PRC") and determined on a basis that includes the recovery of the cost of power production by the Company's Generation and Trading Operations and a return on the related assets, among other things. 8 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (2) Nature of Business and Segment Information (Continued) UTILITY OPERATIONS Electric The Company provides jurisdictional retail electric service to a large area of north central New Mexico, including the cities of Albuquerque and Santa Fe, and certain other areas of New Mexico. The Company owns or leases 2,887 circuit miles of transmission lines, interconnected with other utilities in New Mexico and east and south into Texas, west into Arizona, and north into Colorado and Utah. Gas The Company's gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe. The Company's customer base includes both sales-service customers and transportation-service customers. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. GENERATION AND TRADING OPERATIONS The Company's generation and trading operations serve four principal markets. These include sales to the Company's Utility Operations to cover jurisdictional electric demand, sales to firm-requirements wholesale customers, other contracted sales to third parties for a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time and energy sales made on an hourly basis at fluctuating, spot-market rates. These latter two markets constitute the Company's power trading operations. As of September 30, 2001 the total net generation capacity of facilities owned or leased by the Company was 1,653 MW, including a 132 MW power purchase contract accounted for as an operating lease. In addition to its generation capacity, the Company purchases power in the open market. UNREGULATED The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a New Mexico corporation and is currently engaged in certain unregulated business ventures. In July 2001, the Board of Directors of Avistar decided to wind down all operations except for Avistar's Reliadigm business unit, which provides maintenance solutions to the electric power industry. Avistar had previously divested itself of its Energy Partners business unit and liquidated Axon Field Services and Pathways Integration. In addition, the transfer of the Sangre de Cristo Water Company operations to the City of Santa Fe was completed in the third quarter. All remaining non-Reliadigm investments were written-off with the exception of Avistar's investment in Nth Power, an energy related venture capital fund. In the third quarter 9 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (2) Nature of Business and Segment Information (Continued) of 2001, the Company recorded a related charge of $4.2 million. The Company had previously taken charges of $13.0 million to reflect these activities and the impairment of its Avistar investments. Unregulated also includes certain corporate activities, which are not material. REGULATION AND RESTRUCTURING In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for corporate separation of supply service and energy-related service assets to be deregulated from distribution and transmission service assets that would continue to be regulated. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The amendments to the Restructuring Act required that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of supply service and energy-related service assets from distribution and transmission service assets, by July 1, 2001. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented. The Company believes that its ability to form a new holding company and expand generation assets in an unregulated environment will give it the flexibility it needs to pursue its strategic plan despite the delay in customer choice and corporate separation. The Company is unable to predict the form its restructuring will take under the delayed implementation of customer choice. The formulation of a restructuring plan will be dependent on future business conditions at the expected time customer choice is implemented (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Issues Facing The Company - - Recovery of Certain Costs Under The Restructuring Act" below). In June 2000, shareholders approved the mandatory share exchange necessary to implement a holding company structure, with the holding company to be named Manzano Corporation. In April 2001, the Company's Board of Directors amended the articles of incorporation of the proposed holding company to rename the holding company "PNM Resources, Inc." (PNM Resources). In April 2001, the Company filed its application for the creation of a holding company under the terms of the Restructuring Act, as amended. The PRC issued an order approving formation of a holding company on June 28, 2001. The order limits the Company's proposed utility subsidiary's ability to pay dividends to the parent holding company, without prior PRC approval, to annual current earnings determined 10 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (2) Nature of Business and Segment Information (Continued) on a rolling four quarter basis and imposes certain regulatory requirements regarding merchant generation plants. The Company believes that certain conditions imposed by the PRC order are unlawful and could have an adverse effect on the Company's ability to execute its growth strategy. On July 27, 2001, the Company asked the PRC to reconsider certain conditions imposed by the order. The PRC did not act on the Company's request, and the request was deemed denied on August 16, 2001. Despite this adverse ruling, the Company plans to proceed with its plans to activate PNM Resources and complete the mandatory share exchange. At the same time, the Company will continue with its efforts to minimize the adverse effects of the order. On September 14, 2001, the Company asked the New Mexico Supreme Court to review the holding company order. The Company believes the PRC exceeded its jurisdiction and placed certain conditions on the new corporate structure that the Company believes are unlawful. The Attorney General has filed a cross-appeal. The Company is unable to predict the outcome of its appeal or cross-appeal. In filings with the PRC, Staff and other parties have raised the issue whether the Company should be allowed to form the holding company pending appeal. The Company has filed its response and intends to vigorously defend its right to form the holding company pending appeal. The Company is unable to predict what action the PRC may take regarding this issue. RISKS AND UNCERTAINTIES The Company's future results may be affected by changes in regional economic conditions; fluctuations in fuel, purchased power and gas prices; the actions of utility regulatory commissions, including rulings regarding price mitigation; changes in law; environmental regulations and external factors such as the weather. As a result of State and Federal regulatory reforms, the public utility industry is undergoing a fundamental change. As this occurs, the electric generation business is transforming into a competitive marketplace. In turn, these reforms are being revisited as a result of the energy crisis in California, that occurred in 2000 and early 2001, as well as the related increased prices for power elsewhere in the Western United States and concerns over inadequate capacity. The Company's future results will be impacted by its ability to recover its stranded costs, the market price of electricity and natural gas costs incurred previously in providing power generation to electric service customers, the costs of transition to an unregulated status, future regulatory actions, and the price of power in the wholesale markets. In addition, as a result of deregulation, the Company may face competition from companies with greater financial and other resources. 11 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (2) Nature of Business and Segment Information (Continued) Summarized financial information by business segment for the three months ended September 30, 2001 and 2000 is as follows:
Utility ------------------------------- Generation Unregulated Electric Gas Total and Trading and Other Consolidated -------- --- ------ ----------- ------------ ------------ (In thousands) 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..... 8,220 5,400 13,620 10,564 10 24,194 Interest income................... 555 126 681 9,841 1,585 12,107 Interest charges.................. 5,610 2,423 8,033 4,470 3,177 15,680 Operating income (loss)........... 18,284 650 18,934 33,223 (4,735) 47,422 Income tax expense (benefit) from continuing operations...... 8,186 (1,390) 6,796 21,794 (6,246) 22,344 Segment net income (loss)......... 12,490 (2,120) 10,370 33,256 (10,851) 32,775 Total assets...................... 799,607 466,550 1,266,157 1,522,354 297,567 3,086,078 Gross property additions.......... 18,577 11,378 29,955 14,856 4,375 49,186 2000: Operating revenues: External customers............. $149,970 $ 55,133 $205,103 $294,131 $ 243 $499,477 Intersegment revenues.......... 177 - 177 90,638 - 90,815 Depreciation and amortization..... 7,856 4,989 12,845 10,170 7 23,022 Interest income................... 329 137 466 10,175 1,340 11,981 Interest charges.................. 4,342 2,645 6,987 9,013 108 16,108 Operating income (loss)........... 19,092 2,863 21,955 32,321 (6,824) 47,452 Income tax expense (benefit) from continuing operations...... 9,464 2,689 12,153 23,114 (5,470) 29,797 Segment net income (loss)......... 15,553 3,922 19,475 37,564 (10,126) 46,913 Total assets...................... 768,912 419,579 1,188,491 1,447,513 156,176 2,792,180 Gross property additions.......... 16,406 13,350 29,756 17,605 (511) 46,850
12 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (2) Nature of Business and Segment Information (Continued) Summarized financial information by business segment for the nine months ended September 30, 2001 and 2000 is as follows:
Utility ------------------------------ Generation Unregulated Electric Gas Total and Trading and Other Consolidated -------- --- ----- ----------- ----------- ------------ (In thousands) 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..... 24,311 16,023 40,334 31,981 28 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)........... 48,674 15,281 63,955 151,906 (10,592) 205,269 Income tax expense (benefit) from continuing operations...... 21,883 4,560 26,443 88,667 (29,203) 85,907 Segment net income (loss)......... 33,393 6,959 40,352 135,302 (29,730) 145,924 Total assets...................... 799,607 466,550 1,266,157 1,522,354 297,567 3,086,078 Gross property additions.......... 47,082 28,836 75,918 78,674 10,534 165,126 2000: Operating revenues: External customers............. $406,034 $204,193 $610,227 $537,647 $ 1,935 $1,149,809 Intersegment revenues.......... 530 - 530 245,330 - 245,860 Depreciation and amortization..... 23,903 14,870 38,773 30,873 18 69,664 Interest income................... 722 384 1,106 29,697 4,776 35,579 Interest charges.................. 13,195 8,380 21,575 27,041 413 49,029 Operating income (loss)........... 48,729 12,942 61,671 62,610 (18,228) 106,053 Income tax expense (benefit) from continuing operations...... 22,586 5,989 28,575 35,596 (11,988) 52,183 Segment net income (loss)......... 36,090 8,586 44,676 61,612 (19,437) 86,851 Total assets...................... 768,912 419,579 1,188,491 1,447,513 156,176 2,792,180 Gross property additions.......... 38,343 24,562 62,905 34,821 2,342 100,068
13 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (3) Comprehensive Income Changes in comprehensive income are as follows:
Three Months Ended Nine Months Ended September 30, September 30, ------------------------- ------------------------ 2001 2000 2001 2000 ------------ ------------ ------------ ----------- (In thousands) Net Earnings............................................ $32,775 $46,913 $145,924 $86,851 ------------ ------------ ------------ ----------- Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities: Unrealized holding gains (losses) arising during the period........................ (1,459) 695 (885) 2,081 Less reclassification adjustment for gains (losses)... 341 (1,013) (693) (2,961) Minimum pension liability adjustment.................. 780 - - - Mark-to-market adjustment for certain derivative transactions (see Footnote 4) Initial implementation of SFAS 133 designated cash flow hedges.................... 6,148 - - - Change in fair market value of designated cash flow hedges.................... (17,930) (8,309) - - ------------ ------------ ------------ ----------- Total Other Comprehensive Income (Loss).............. (19,048) (318) (2,959) (880) ------------ ------------ ------------ ----------- Total Comprehensive Income.............................. $13,727 $46,595 $142,965 $85,971 ============ ============ ============ ===========
The Company's investments held in grantor trusts for nuclear decommissioning and certain retirement benefits are classified as available-for-sale, and accordingly unrealized holding gains and losses are recognized as a component of comprehensive income. Realized gains and losses are included in earnings. Net losses to the Company's pension plans not yet recognized as net periodic pension costs (or additional minimum liability) are reported as a component of comprehensive income. Changes in the liability are adjusted as necessary. All components of comprehensive income are recorded, net of any tax benefit or expense. A deferred asset or liability is established for the resulting temporary difference. (4) Financial Instruments The Company implemented Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"), as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at their fair value. SFAS 133, as amended, also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset related results on the hedged item in the income statement, 14 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (4) Financial Instruments (Continued) and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices and adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. The Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to assess and monitor the financial conditions of counterparties. The Company's receivable with its largest counterparty as of September 30, 2001 was $36.5 million. Natural Gas Contracts Utility Operations Pursuant to a 1997 order issued by the New Mexico Public Utility Commission ("NMPUC"), predecessor to the PRC, the Company's Utility Operations have previously and continue to hedge certain portions of natural gas supply contracts in order to protect the Company's natural gas customers from the risk of adverse price fluctuations in the natural gas market. The cost and financial impacts of all hedge gains and losses are recoverable through the Company's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by the gains or losses generated by these instruments. In 2001, the Company began a hedge program to protect its natural gas customers from price risk during the 2001-2002 heating season through the use of financial hedging tools. As of September 30, 2001, the Company expended approximately $9 million to purchase physical options that limit the maximum amount the Company would pay for gas during the winter heating season. The Company intends to continue this program for the 2001-2002 heating season to the extent it continues to meet the guidelines of the PRC. Generation and Trading Operations The Company's Generation and Trading Operations conduct a hedging program to reduce its exposure to fluctuations in prices for natural gas used as a fuel source for some of its generation. In the first quarter of 2001, the Generation Operations purchased futures contracts 15 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (4) Financial Instruments (Continued) for a portion of its anticipated natural gas needs in the third and fourth quarters. As of September 30, 2001, the open futures contracts lock in the Company's natural gas purchase prices at $2.12 to $5.90 per MMBTU and have a notional principal of $3.9 million. Simultaneously, a delivery location basis swap was purchased for quantities corresponding to the futures quantities to protect against price differential changes at the specific delivery points. The Company is accounting for these transactions as cash flow hedges; accordingly, gains and losses related to these transactions are deferred and recorded as a component of Other Comprehensive Income. These gains and losses are reclassified and recognized in earnings as an adjustment to the Company's cost of fuel when the hedged forecasted transaction affects earnings. The assessment of hedge effectiveness is based on the changes in the futures contract price as adjusted for the delivery point basis swap. There was no hedge ineffectiveness recognized in the nine months ended September 30, 2001. Electricity Contracts To take advantage of market opportunities associated with the purchase and sale of electricity, the Company's Generation and Trading Operations periodically enter into derivative financial instrument contracts. The Company generally accounts for these financial instruments as trading activities under the accounting guidelines set forth under The Emerging Issues Task Force ("EITF") Issue No. 98-10. As a result, these contracts are marked to market at the end of each period. The related gains and losses for these derivative instruments are recorded as adjustments to operating revenues. Through September 30, 2001, the Company's Generation and Trading Operations settled trading contracts for the sale of electricity that generated $70.7 million of electric revenues by delivering 610 million KWh. The Company purchased $69.5 million or 591 million KWh of electricity to support these contractual sales and other open market sales opportunities. As of September 30, 2001, the Company's Generation and Trading Operations had open trading contract positions to buy $89.8 million and to sell $47.6 million of electricity. At September 30, 2001, the Company had a gross mark-to-market gain (asset position) on these trading contracts of $24.7 million and a gross mark-to-market loss (liability position) of $56.2 million, with net mark-to-market losses of $31.5 million. The mark-to-market valuation is recognized in earnings each period. In addition, the Company's Generation and Trading Operations enter into forward physical contracts for the sale of the Company's electric capacity in excess of its jurisdictional needs, including reserves, or the purchase of jurisdictional needs, including reserves, when resource shortfalls exist. The Company generally accounts for these derivative financial instruments as normal sales and purchases as defined by SFAS 133, as amended. The Company from time to time makes forward purchases to serve its jurisdictional needs when the cost of purchased power is less than the incremental cost of its generation. At September 30, 2001, the Company had open forward positions classified as normal sales of electricity of $63.2 million and normal purchases of electricity of $38.0 million. 16 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (4) Financial Instruments (Continued) The Company designated certain forward purchase contracts for electricity as cash flow hedges. The Company's designated cash flow hedges at September 30, 2001, were forward purchase contracts for the purchase of electric power for forecasted jurisdictional use during planned outages in 2001 and certain other forecasted sales. The hedged risks associated with these instruments are the changes in cash flows related to forecasted purchase of electricity due to changes in the price of electricity on the spot market. Assessment of hedge effectiveness will be based on the changes in the forward price of electricity. There was no hedge ineffectiveness recognized in the three months ended September 30, 2001. The Company's Generation and Trading Operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. The Company's value-at-risk calculation considers this exposure (see "Item 3. Quantitative and Qualitative Disclosure About Market Risk"). Hedge of Trust Assets In February 2001, the Company terminated certain financial derivatives based on the Standard & Poor's ("S&P") 500 Index. These instruments were used to limit potential loss on investments for nuclear decommissioning, executive retirement and retiree medical benefits due to adverse market fluctuations. The Company recognized a realized gain of $0.5 million (pretax) as a result. Previously, the Company had marked-to-market the financial instruments to match the hedged investment activity. 17 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (5) Earnings Per Share In accordance with SFAS No. 128, Earnings per Share, dual presentation of basic and diluted earnings per share has been presented in the Consolidated Statements of Earnings. The following reconciliation illustrates the impact on the share amounts of potential common shares and the earnings per share amounts for September 30 (in thousands except per share amounts):
Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ----------- ----------- ----------- ----------- Basic: Net Earnings............................................ $ 32,775 $ 46,913 $145,924 $ 86,851 Preferred Stock Dividend Requirements................... 147 147 440 440 ----------- ----------- ----------- ----------- Net Earnings Applicable to Common Stock................. $ 32,628 $ 46,766 $145,484 $ 86,411 =========== =========== =========== =========== Average Number of Common Shares Outstanding............. 39,118 39,363 39,118 39,623 =========== =========== =========== =========== et Earnings per Common Share (Basic).................... $ 0.83 $ 1.19 $ 3.72 $ 2.18 =========== =========== =========== =========== Diluted: Net Earnings Applicable to Common Stock Used in basic calculation............................. $ 32,628 $ 46,766 $145,484 $ 86,411 =========== =========== =========== =========== Average Number of Common Shares Outstanding............. 39,118 39,363 39,118 39,623 Diluted Effect of Common Stock Equivalents (a).......... 630 288 653 125 ----------- ----------- ----------- ----------- Average Common and Common Equivalent Shares Outstanding........................................... 39,748 39,651 39,771 39,748 =========== =========== =========== =========== Net Earnings per Share of Common Stock (Diluted)........ $ 0.82 $ 1.18 $ 3.66 $ 2.17 =========== =========== =========== ===========
(a) Excludes the effect of average anti-dilutive common stock equivalents related to out-of-the-money options of 92,949 and 140,448 for the three months and nine months ended September 30, 2000. There were no anti-dilutive common stock equivalents in 2001. (6) Commitments and Contingencies Texas-New Mexico Power Wholesale Power Supply Contract In July 2001, the Company entered into a long-term wholesale power contract with Texas-New Mexico Power ("TNMP") to provide power to serve TNMP's firm retail customers. The contract has a term of 5 1/2 years commencing July 1, 2001. The Company will provide varying amounts of firm power on demand to complement existing TNMP contracts. As those contracts expire, the Company will replace them and become TNMP's sole supplier beginning January 1, 2003. In the last year of the contract, it is estimated that TNMP will need 114 megawatts of firm power. 18 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (6) Commitments and Contingencies (Continued) Construction Commitment The Company has committed to purchase five combustion turbines totaling $151.3 million. The turbines are for three planned power generation plants with a combined capacity of 657 MWs. The plants estimated cost of construction is approximately $400.3 million. The Company has expended $89.4 million as of September 30, 2001. In November, 2001, the Company plans to break ground for a new 135 MW single cycle gas turbine plant on a site in Southern New Mexico. Currently the Company plans to expand the facility to 540 MW by 2003. Contracts have not been finalized on the remaining planned construction. The planned plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. Such construction is not anticipated to be added to the rate base. Natural Gas Explosion On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The cause of the leak is unknown and the Company is conducting an investigation into the explosion. The Company also is cooperating with an investigation of the incident by the New Mexico Public Regulation Commission's Pipeline Safety Bureau. One lawsuit against the Company for personal injuries by a person working in the building at the time of the explosion has been filed and served on the Company. Several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur. There can be no assurance that the outcome of this matter will not have a material adverse impact on the results of operations and financial position of the Company. Implementation of Customer Billing System On November 30, 1998, the Company implemented a new customer billing system. Due to a significant number of problems associated with the implementation of the new billing system, the Company was unable to generate appropriate bills for all its customers through the first quarter of 1999 and was unable to analyze delinquent accounts until November 1999. As a result of the delay of normal collection activities, the Company incurred a significant increase in delinquent accounts, many of which occurred with customers that no longer have active accounts with the Company. The Company continued its analysis and collection efforts of its delinquent accounts resulting from the problems associated with the implementation of the new customer billing system throughout 2000 and identified additional bad debt exposure. As a result, the Company significantly increased its estimated bad debt costs throughout 1999 and 2000. By the end of 2000, the Company completed its analysis of its delinquent accounts and resumed its normal collection procedures. In addition, due to the significantly higher natural gas prices experienced in November and December 2000, the Company increased its bad debt expense by approximately $1 million 19 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (6) Commitments and Contingencies (Continued) for the nine months ended September 30, 2001 and $2 million for the year ended December 31, 2000 in anticipation of higher than normal delinquency rates. Based upon information available at September 30, 2001, the Company believes the allowance for doubtful accounts of $8.3 million is adequate for management's estimate of potential uncollectible accounts. The following is a summary of the allowance for doubtful accounts during the nine months ended September 30, 2001 and the year ended December 31, 2000: September 30, December 31, 2001 2000 ------------- ------------ Allowance for doubtful accounts, beginning of year.......................................... $ 8,963 $ 12,504 Bad debt accrual................................... 9,980 3,373 Less: Write-off (adjustments) of uncollectible Accounts......................................... 13,521 4,019 ------------ ------------ Allowance for doubtful accounts, end of period .... $ 8,317 $ 8,963 ============ ============ PVNGS Liability and Insurance Matters The PVNGS participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under Federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the primary liability insurance limit, the Company could be assessed retrospective adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88 million, subject to an annual limit of $10 million per reactor per incident. Based upon the Company's 10.2% interest in the three PVNGS units, the Company's maximum potential assessment per incident for all three units is approximately $27.0 million, with an annual payment limitation of $3 million per incident. If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue raising measures on the nuclear industry to pay claims. The United States Nuclear Regulatory Commission and Congress are reviewing the related laws. The Company cannot predict whether or not Congress will change the law. However, certain changes could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by the lessors. Such an occurrence could require the Company to, among other things, (i) pay the lessor and the equity investor, in return for the investor's interest in PVNGS, cash in the amount as provided in the lease and (ii) assume debt obligations relating to the PVNGS lease. The PVNGS participants maintain "all-risk" (including nuclear hazards) insurance for nuclear property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion as of January 1, 2001. The Company is a member of an industry mutual insurer which provides both the "all-risk" and increased cost of generation insurance to the 20 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (6) Commitments and Contingencies (Continued) Company. In the event of adverse losses experienced by this insurer, the Company is subject to an assessment. The Company's maximum share of any assessment is approximately $4.8 million per year. This insurance coverage is subject to certain policy conditions and exclusions. PVNGS Decommissioning Funding The Company has a program for funding its share of decommissioning costs for PVNGS. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. The results of the 1998 decommissioning cost study indicated that the Company's share of the PVNGS decommissioning costs excluding spent fuel disposal will be approximately $180 million (in 2001 dollars). The estimated market value of the trusts at the end of September 30, 2001 was approximately $48 million. Nuclear Spent Fuel and Waste Disposal Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "Waste Act"), the United States Department of Energy ("DOE") is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. Under the Waste Act, DOE was to develop the facilities necessary for the storage and disposal of spent nuclear fuel and to have the first facility in operation by 1998. DOE has announced that such a repository now cannot be completed before 2010. The operator of PVNGS has capacity in existing fuel storage pools at PVNGS which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of PVNGS through 2002, and believes it could augment that storage with the new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. The Company currently estimates that it will incur approximately $41 million (in 1998 dollars) over the life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. The Company accrues these costs as a component of fuel expense, meaning the charges are accrued as the fuel is burned. The operator of PVNGS currently believes that spent fuel storage or disposal methods will be available for use by PVNGS to allow its continued operation beyond 2002. Other There are various other claims and lawsuits pending against the Company and certain of its subsidiaries, in addition to the matters discussed above. The Company is also subject to Federal, state and local environmental laws and regulations, and is currently participating in the investigation and remediation of numerous sites. In addition, the Company periodically enters into financial commitments in connection with business operations. It is not possible at this time for the Company to determine fully the effect of all litigation on its consolidated financial statements. However, the Company has recorded a liability where the litigation effects can be estimated and where an outcome is considered probable. The Company does not expect that any of these other matters not discussed in detail above will have a material adverse effect on its financial condition or results of operations. 21 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (7) Environmental Issues The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though the past acts may have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes. The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company, records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). The Company's recorded estimated minimum liability to remediate its identified sites is $6.8 million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $11.6 million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company. For the nine months ended September 30, 2001, the Company spent $1.2 million for remediation. The majority of the September 30, 2001, environmental liability is expected to be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company. (8) Western Resources Acquisition On November 9, 2000, the Company and Western Resources, Inc. ("Western Resources") announced that both companies' boards of directors approved an agreement under which the 22 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (8) Western Resources Acquisition (Continued) Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. Due to recent actions by the Kansas Corporation Commission ("KCC"), the Company believes that the transaction cannot be accomplished under the terms of the present acquisition agreement if the orders remain in effect (see below). On October 12, 2001, the Company filed suit in the Supreme Court of New York ("NY Court") asking the NY Court to find that it is impossible to complete the proposed transaction under the original terms. The Company also asked the NY Court to rule that an electric rate reduction mandated by the KCC is a material adverse effect removing the obligation to effect the transaction. Western Resources' response to the Complaint is due on November 26, 2001. Present Acquisition Agreement Under the present agreement, the Company and Western Resources, whose utility operations consist of its Kansas Power and Light division and Kansas Gas and Electric subsidiary, will both become subsidiaries of a new holding company to be named at a future date. Prior to the consummation of this combination, Western Resources will reorganize all of its non-utility assets, including its 85 percent stake in Protection One and its 45 percent investment in ONEOK, into Westar Industries which will be split off to Western Resources' shareholders, prior to the acquisition of Western's electric utility businesses by the Company. Under the present agreement, the new holding company will issue 55 million of its shares, subject to adjustment, to Western Resources' shareholders and Westar Industries. Before any adjustments, the new company will have approximately 94 million shares outstanding, of which approximately 41 percent will be owned by former Company shareholders and 59 percent will be owned by former Western Resources shareholders and Westar Industries. In the present transaction, each Company share will be exchanged on a one-for-one basis for shares in the new holding company. The portion of each Western Resources share not converted into Westar Industries stock in connection with the split off will be exchanged for a fraction of a share of the new holding company. This exchange ratio will be finalized at closing, depending on the impact of certain adjustments to the transaction consideration. Under the present agreement, Western Resources and Westar Industries have been given a limited incentive to reduce Western Resources' net debt balance prior to the consummation of the transaction by selling non-utility assets or through certain other debt reduction activities. The present agreement contains a mechanism to adjust the transaction consideration based on certain activities not affecting the utility operations, which increase the equity of the utility. In addition, Westar Industries has the option of making equity infusions into Western Resources that will be used to reduce the utility's net debt balance prior to closing. Up to $641 million of additional equity infusions and existing intercompany receivables may be used to purchase additional new holding company common and convertible preferred stock. The effect of these activities would be to increase the number of new holding company shares to be issued to all Western Resources shareholders (including Westar Industries) in the present transaction. 23 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (8) Western Resources Acquisition (Continued) In February 2001, Westar Industries purchased 14.4 million Western Resources common shares at $24.358 per share (based on a 20-day look-back price at February 28, 2001) at an aggregate price of $350 million. As a result of this equity contribution, under the present agreement, the acquisition consideration may be adjusted to include an additional 4.3 million shares of the new holding company depending on the impact of future transactions between Western Resources and Westar Industries. Under the present agreement, the transaction will be accounted for as a reverse acquisition by the Company as the former Western Resources shareholders will receive the majority of the voting interests in the new holding company. For accounting purposes, Western Resources will be treated as the acquiring entity. Accordingly, all of the assets and liabilities of the Company will be recorded at fair value in the business combination as required by the purchase method of accounting. In addition, the operations of the Company will be reflected in the reported results of the combined company only from the date of acquisition. Based on the volume weighted average closing price of the Company's common stock over the two days prior and two days subsequent to the announcement of the transaction of $24.149 per share, the indicated equity consideration of the present transaction is approximately $945 million, excluding the potential issuance of additional shares discussed above. There is approximately $2.9 billion of existing Western Resources debt giving the transaction an aggregate enterprise value of approximately $3.8 billion. There are plans for the new holding company to reduce and refinance a portion of the Western Resources debt. Under the present agreement, the successful split-off of Westar Industries from Western Resources is required prior to the consummation of the transaction. The present transaction is also conditioned upon, among other things, approvals from both companies' shareholders and customary regulatory approvals from the KCC, the PRC, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Federal Communications Commission and either the Federal Trade Commission or the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse regulatory outcome related to other actions involving rate making or approval of regulatory plans may affect the consummation of the transaction. The new holding company would be expected to register as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. Recent Actions by the KCC On July 20, 2001, the KCC issued an order prohibiting Western Resources from proceeding with the split-off of Westar Industries. The KCC ruled that the split-off, as presently designed, is inconsistent with the public interest. The KCC also ruled that the adverse impacts of the split-off on ratepayers could not be cured by a merger and directed Western Resources to file a financial plan within 90 days to restore Western Resources' financial ratings to the investment grade level of similarly situated electric public utilities. Western Resources filed for reconsideration of the order. On October 3, 2001, the KCC issued its order on reconsideration of 24 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (8) Western Resources Acquisition (Continued) the split-off order, reaffirming its prior order prohibiting the split-off as presently designed and confirming that a merger would not cure the problems associated with the split-off. In October 2001, Western Resources filed petitions for judicial review in the District Court of Shawnee County, Kansas, of the split-off order and the reconsideration order. On July 25, 2001, the KCC issued an order reducing the rates of Western Resources electric utilities by the net amount of $22.7 million annually. Western Resources had sought a combined increase of approximately $151 million annually. Western Resources filed for reconsideration of the order and on September 5, 2001, the KCC slightly increased rates resulting in a revised net reduction of approximately $15.7 million annually. Western Resources and other parties in the case filed for reconsideration of the KCC's revised rate order. On October 11, 2001, the KCC issued an order denying all petitions for reconsideration of the revised rate order. On July 30, 2001, the Company and Western Resources issued a joint release stating that the transaction as presently designed would be difficult to complete if the KCC orders remain in effect. The release announced that the Company and Western Resources would begin discussions on how to modify the transaction to make it possible to obtain necessary regulatory approvals. On August 13, 2001, the Company announced that Western Resources had decided to discontinue the talks about modifying the transaction and desired to attempt to pursue completion of the transaction as currently structured. The Company announced that it continues to believe that the transaction cannot be accomplished on its present terms due to the KCC orders. In addition, the Company announced that it believes that the rate case order will result in a material adverse effect on the financial condition of the combined companies and that there will be a failure of key conditions to consummation of the transaction if the KCC orders remain in effect. Western Resources has advised the Company that it does not believe that the rate case order results in a material adverse effect. Western Resources has requested that the Company file for regulatory approvals of the transaction as presently designed, despite the fact that the transaction requires the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as presently designed, the Company filed suit on October 12, 2001, in New York state court seeking declarations that the transaction could not be accomplished as presently designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as presently designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. The Company is unable to predict the outcome of this proceeding. 25 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (8) Western Resources Acquisition (Continued) On November 6, 2001, Western Resources filed its financial plan for restructuring debt pursuant to the KCC's July 20 order. The plan is essentially comprised of two parts. The first part is stated by Western Resources as being designed to reduce debt by $100 to $175 million in the next several months by means of a rights offering of between $8.7 million and $19.1 million Westar Industries shares to Western Resources shareholders, representing between 10.2% and 19.9% of outstanding shares of Westar Industries. The second part is stated by Western Resources as being designed to reduce debt below $1.8 billion over the next one to three years through the sale by Western Resources of its Westar Industries common stock or Western Resources shares. The second part would not take place unless Westar Industries' stock price trades for 45 consecutive trading days at a price 25% higher than the price necessary to reduce Western Resources' debt below $1.8 billion. The first part of the plan is acknowledged by Western Resources to be similar to the split-off ruled unlawful by the KCC but Western Resources asserts that it has made certain modifications in an attempt to address concerns raised by the KCC. The Company continues to monitor the proceedings in Kansas and intends to pursue the litigation in New York State Court. (9) New and Proposed Accounting Standards Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the recognition of a liability for legal obligations associated with the retirement of a tangible long-lived asset that result from the acquisition, construction or development and/or the normal operation of a long-lived asset. The asset retirement obligation is required to be recognized at its fair value when incurred. The cost of the asset retirement obligation is required to be capitalized by increasing the carrying amount of the related long-lived asset by the same amount as the liability. This cost must be expensed using a systematic and rational method over the related asset's useful life. SFAS 143 is effective for the Company beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and is unable to predict its impact on the Company's operating results and financial position at this time. Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS 144"). In August 2001, the FASB issued SFAS 144. The statement amends certain requirements of the previously issued pronouncement on asset impairment, Statement of Financial Accounting Standards No. 121 ("SFAS 121"). SFAS 144 removes goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position. 26 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS All references to the Company refer to Public Service Company of New Mexico or, as the context requires, its proposed successor holding company PNM Resources, Inc. (see "Restructuring the Electric Utility Industry" below). The following is management's assessment of the Company's financial condition and the significant factors affecting the results of operations. This discussion should be read in conjunction with the Company's consolidated financial statements and Part I, Item 3. - Legal Proceedings. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. OVERVIEW The Company is an investor-owned integrated public utility primarily engaged in the generation, transmission, distribution and sale of electricity and in the transmission, distribution and sale of natural gas within the State of New Mexico. As it currently operates, the Company's principal business segments are Utility Operations, which include the Electric Product Offering ("Electric") and the Natural Gas Product Offering ("Gas"), and Generation and Trading Operations ("Generation and Trading"). Electric consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment for accounting purposes due to its immateriality, and for purposes of this discussion, it is combined with the distribution product offering. UTILITY OPERATIONS Electric The Company provides jurisdictional retail electric service to a large area of north central New Mexico, including the City of Albuquerque and the City of Santa Fe, and certain other areas of New Mexico. The following table shows electric sales by customer class: ELECTRIC SALES (Megawatt hours) Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ------------- ---------- ----------- ----------- Residential........... 593,453 592,187 1,676,271 1,638,633 Commercial............ 931,937 912,951 2,447,231 2,367,363 Industrial............ 425,299 399,364 1,210,266 1,166,295 Other................. 75,751 74,066 182,450 183,088 ------------- ---------- ----------- ----------- 2,026,440 1,978,568 5,516,218 5,355,379 ============= ========== =========== =========== 27 The following table shows electric revenues by customer class: ELECTRIC REVENUES (Thousands of dollars) Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ------------ ----------- ----------- ----------- Residential............... $ 50,002 $ 50,782 $142,785 $140,582 Commercial................ 68,363 68,574 183,372 179,269 Industrial................ 21,836 20,691 62,161 60,114 Other..................... 13,511 10,100 36,461 26,599 ------------ ----------- ----------- ----------- $153,712 $150,147 $424,779 $406,564 ============ =========== =========== =========== Average customers......... 378,336 369,063 376,297 367,400 ============ =========== =========== =========== The Company owns or leases 2,887 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. Due to rapid load growth in recent years, most of the capacity on this transmission system is fully committed and there is no additional access available on a firm commitment basis. These factors, together with significant physical constraints in the system, limit the ability to wheel power into the Company's service area from outside the state. Gas The Company's Gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe. The Company's gas customer base includes both sales-service customers and transportation-service customers. Sales-service customers purchase natural gas and receive transportation and delivery services from the Company for which the Company receives both cost-of-gas and cost-of-service revenues. Additionally, the Company makes occasional gas sales to off-system customers. Off-system sales deliveries generally occur at interstate pipeline interconnects with the Company's system. Transportation-service customers, who procure gas independently of the Company and contract with the Company for transportation and related services, provide the Company with cost-of-service revenues only. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. These contracts are generally sufficient to meet the Company peak-day demand. 28 The following table shows gas throughput by customer class: GAS THROUGHPUT (Thousands of decatherms) Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ---------- ---------- ---------- ---------- Residential........... 2,270 2,240 18,357 17,081 Commercial............ 1,242 1,049 6,867 5,862 Industrial............ 144 2,316 3,665 3,641 Transportation*....... 16,842 14,905 41,243 34,579 Other................. 763 1,593 3,541 5,651 ---------- ---------- ---------- ---------- 21,261 22,103 73,673 66,814 ========== ========== ========== ========== The following table shows gas revenues by customer: GAS REVENUES (Thousands of dollars) Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ---------- ---------- ----------- ----------- Residential............... $21,709 $24,084 $ 188,113 $ 117,383 Commercial................ 6,711 7,041 56,375 31,823 Industrial................ 623 11,726 26,541 16,404 Transportation*........... 6,025 3,651 16,437 10,582 Other..................... 4,581 8,631 31,204 28,001 ---------- ---------- ----------- ----------- $39,649 $55,133 $ 318,670 $ 204,193 ========== ========== =========== =========== Average customers......... 441,557 426,627 442,982 428,384 ========== ========== =========== =========== *Customer-owned gas. GENERATION AND TRADING OPERATIONS The Company's Generation and Trading Operations serve four principal markets. Sales to the Company's Utility Operations to cover jurisdictional electric demand and sales to firm-requirements wholesale customers, sometimes referred to collectively as "system" sales, comprise two of these markets. The third market consists of other contracted sales to third parties for which the Generation and Trading Operations commit to deliver a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time. The fourth market consists of economy energy sales made on an hourly basis at fluctuating, spot-market rates. Sales to the third and fourth markets are sometimes referred to collectively as "off-system" sales. Off-system sales include the Company's energy trading activities. 29 The following table shows sales by customer class: GENERATION AND TRADING SALES BY MARKET (Megawatt hours)
Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ------------ ------------ ------------ ------------- Intersegment sales.................. 2,026,439 1,978,568 5,516,218 5,355,379 Firm-requirement wholesale.......... 165,642 114,340 441,376 209,096 Other contracted off-system sales... 1,977,917 2,149,539 5,483,401 5,664,280 Economy energy sales................ 1,373,454 1,029,641 3,901,723 3,729,391 ------------ ------------ ------------ ------------- 5,543,452 5,272,088 15,342,718 14,958,146 ============ ============ ============ =============
The following table shows revenues by customer class: GENERATION AND TRADING REVENUES BY MARKET (Thousands of dollars)
Three Months Ended Nine Months Ended September 30, September 30, 2001 2000 2001 2000 ------------- ----------- -------------- ------------ Intersegment revenues..................... $ 95,413 $ 90,638 $ 259,726 $ 245,330 Firm-requirement wholesale................ 8,663 5,952 16,026 9,577 Other contracted off-system revenues...... 362,729 149,979 803,620 278,484 Economy energy sales...................... 60,137 123,570 486,348 246,195 Other*.................................... (2,998) 14,630 (25,853) 3,391 ------------- ----------- -------------- ------------ $ 523,944 $384,769 $ 1,539,867 $ 782,977 ============= =========== ============== ============
*Includes mark-to-market gains/(losses). See footnote (4) in Notes to Consolidated Financial Statements. The Company has ownership interests in certain generating facilities located in New Mexico, including the San Juan Generating Station and the Four Corners Power Plant, coal fired plants. In addition, the Company has ownership and leasehold interests in Palo Verde Nuclear Generating Station ("PVNGS") located in Arizona. These generation assets are used to supply retail and wholesale customers. The Company also owns Reeves Generating Station and Las Vegas Generating Station, gas and oil fired plants, that are used for reliability purposes or to generate electricity for the wholesale market during certain demand periods in the Generation and Trading Operations' wholesale power markets. As of September 30, 2001, the total net generation capacity of facilities owned or leased by the Company was 1,653 MW, including a 132 MW power purchase contract accounted for as an operating lease. In addition to its generation capacity, the Generation and Trading Operations purchases power in the open market. 30 AVISTAR The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a New Mexico corporation and is currently engaged in certain unregulated, non-utility business ventures. The PRC authorized the Company to invest $50 million in equity in Avistar and to enter into a reciprocal loan agreement for up to $30 million. The Company has currently invested $50 million in Avistar and has no amounts outstanding under the reciprocal loan agreement. In July 2001, the Board of Directors of Avistar decided to wind down all operations except for Avistar's Reliadigm business unit, which provides maintenance solutions to the electric power industry. Avistar had previously divested itself of its Energy Partners business unit and liquidated Axon Field services and Pathways Integration. In addition the transfer of the Sangre de Cristo Water Company operations to the City of Santa Fe was completed in the third quarter. All remaining non-Reliadigm investments were written-off with the exception of Avistar's investment in Nth Power, an energy related venture capital fund. In the third quarter of 2001, the Company recorded a related charge of $4.2 million. The Company had previously taken charges of $13.0 million to reflect these activities and the impairment of its Avistar investments. WESTERN RESOURCES ACQUISITION On November 9, 2000, the Company and Western Resources, Inc. ("Western Resources") announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources' electric utility operations in a tax-free, stock-for-stock transaction. Due to recent actions by the Kansas Corporation Commission ("KCC"), the Company believes that the transaction cannot be accomplished under the terms of the present acquisition agreement if the orders remain in effect. On October 12, 2001, the Company filed suit in the Supreme Court for New York County, New York ("NY Court") asking the NY Court to find that it is impossible to complete the proposed transaction under the original terms. The Company also asked the NY Court to rule that an electric rate reduction mandated by the KCC is a material adverse effect removing the obligations to effect the transaction. (See "Other Issues Facing The Company - Proposed Acquisition of Western Resources Electric Operations" below). RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for corporate separation of supply service and energy-related service assets from distribution and transmission service assets. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. 31 The amendments to the Restructuring Act required that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of supply service and energy-related service assets from distribution and transmission service assets, by July 1, 2001. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented (see "Other Issues Facing the Company - Merchant Plant Filing.") The Company believes that its ability to form a new holding company and expand generation assets in an unregulated environment will give it the flexibility it needs to pursue its strategic plan despite the delay in customer choice and corporate separation. The Company is unable to predict the form its restructuring will take under the delayed implementation of customer choice. The formulation of a restructuring plan will be dependent on future business conditions at the expected time customer choice is implemented (See "Management's Discussion and Analysis of Financial Condition and Results of Operations - Other Issues Facing The Company - Recovery of Certain Costs Under The Restructuring Act" below). In June 2000, shareholders approved the mandatory share exchange necessary to implement a holding company structure, with the holding company to be named Manzano Corporation. In April 2001, the Company's Board of Directors amended the articles of incorporation of the proposed holding company to rename the holding company "PNM Resources, Inc." (PNM Resources). In April 2001, the Company filed its application for the creation of a holding company under the terms of the Restructuring Act, as amended. The PRC issued an order approving formation of a holding company on June 28, 2001. The order limits the Company's proposed utility subsidiary's ability to pay dividends to the parent holding company, without prior PRC approval, to annual current earnings determined on a rolling four quarter basis and imposes certain regulatory requirements regarding merchant generation plants. The Company believes that certain conditions imposed by the PRC order are unlawful and could have an adverse effect on the Company's ability to execute its growth strategy. On July 27, 2001, the Company asked the PRC to reconsider certain conditions imposed by the order. The PRC did not act on the Company's request, and the request was deemed denied on August 16, 2001. Despite this adverse ruling, the Company plans to proceed with its plans to activate PNM Resources and complete the mandatory share exchange. At the same time, the Company will continue with its efforts to minimize the adverse effects of the order. On September 14, 2001, the Company asked the New Mexico Supreme Court to review the holding company order. The Company believes the PRC exceeded its jurisdiction and placed certain conditions on the new corporate structure that the Company believes are unlawful. The Attorney General has filed a cross-appeal. The Company is unable to predict the outcome of its appeal or cross-appeal. In filings with the PRC, the Staff and other parties raised the issue of whether the Company should be allowed to form the holding company pending appeal. The Company has filed its response and intends to vigorously defend its right to form the holding company pending appeal. The Company is unable to predict what action the PRC may take regarding this issue. 32 COMPETITIVE STRATEGY The Restructuring Act, as amended, allows the Company and other utilities to build, operate, invest in or acquire new generating plants for merchant purposes prior to open access with minimum regulatory approvals. These new plants will be excluded from utility rates under the provisions of the law. The cost of new unregulated utility generation resources will serve as a cap for ratemaking purposes, for the price of new resources needed to serve retail customers until customer choice and corporate restructuring is implemented. In addition, the New Mexico Legislature passed, and the Governor signed, an amendment to the Public Utility Act requiring the PRC to act on siting applications for certain generating plants and transmission lines within six months. The PRC is allowed an additional ten months to act on transmission applications that are environmentally sensitive. The Company's Generation and Trading Operations have contributed significant earnings to the Company in recent years as a result of increased off-system sales including its energy trading activities. The Company plans to expand its wholesale energy trading functions which could include an expansion of its generation portfolio as well as expanding trading operations. The Company continuously evaluates its physical asset acquisition strategies to ensure an optimal mix of base-load generation, peaking generation and purchased power in its power portfolio. In addition to the continued energy trading activities, the Company will further focus on opportunities in the market place where excess capacity is disappearing and mid- to long-term market demands are growing. The Company's current business plan calls for increasing generating capacity and wholesale sales. The Company's ability to execute its growth plan may be impacted by the holding company order issued by the PRC on June 28, 2001 (see "Restructuring the Electric Utility Industry" above). The Company intends to spend approximately $1.3 billion over the next five years to grow its generation portfolio. Such growth will be dependent upon the Company's ability to generate funds for the Company's expansion. The Company currently has $223 million of available cash as well as adequate borrowing capacity to fund the expansion program. There can be no assurance that investments in new unregulated generation facilities will be successful or, if unsuccessful, that they will not have a direct or indirect adverse effect on the Company. At the Federal level, there have been, from time to time, a number of proposals on electric restructuring being considered with no concrete timing for definitive actions. None of these proposals have been acted upon by Congress. Issues such as stranded cost recovery, market power, utility regulation reform, the role of states, subsidies, consumer protections and environmental concerns are expected to be considered in the current Congressional session. In addition, the FERC has stated that if Congress mandates electric retail access, it should leave the details of the program to the states with the FERC having the authority to order the necessary transmission access for the delivery of power for the states' retail access programs. Recent federal actions have focused on the energy crisis in California with bills being introduced to require caps on wholesale prices. In addition, the Senate Banking Committee has voted 19-1 to repeal the Public Utility Holding Company Act. In August 2001, the FERC issued a series of Orders requiring existing independent system operators and developing RTOs in the Eastern United States to enter into mediation to form a single RTO in the Northeast and a second in the Southeast. The FERC expressed the desire that four RTO's be formed in the United States, two in the East, one in the Midwest and one in the West. 33 The Company along with other Southwest transmission owners is in the process of forming an RTO including support for a filing that was made on October 16, 2001 with the FERC (see Other Issues Facing the Company - Formation of a Regional Transmission Organization). Although it is unable to predict the ultimate outcome of these legislative initiatives, the Company has been and will continue to be active at both the state and Federal levels in the public policy debates on the restructuring of the electric utility industry. The Company will continue to work with customers, regulators, legislators and other interested parties to find solutions that bring benefits from competition while recognizing the importance of reimbursing utilities for past commitments. RESULTS OF OPERATIONS The following discussion is based on the financial information presented in Footnote 1 of the Consolidated Financial Statements - Nature of Business and Segment Information. The table below sets forth the operating results as percentages of total operating revenues for each business segment. Three Months Ended September 30, 2001 Compared to Three Months Ended September 30, 2000 Three Months Ended September 30, 2001
Utility --------------------------------------------- Generation Electric Gas and Trading ----------------------- --------------------- --------------------- Operating revenues: External customers................... $153,535 99.88% $ 39,649 100.00% $ 428,531 81.79% Intersegment revenues................ 177 0.12 - 0.00 95,413 18.21 ----------- ---------- ---------- --------- ---------- --------- Total revenues....................... 153,712 100.00 39,649 100.00 523,944 100.00 ----------- ---------- ---------- --------- ---------- --------- Cost of energy sold.................... 1,145 0.74 14,330 36.14 414,490 79.11 Intersegment purchases................. 95,413 62.07 - 0.00 177 0.03 ----------- ---------- ---------- --------- ---------- --------- Total fuel costs..................... 96,558 62.82 14,330 36.14 414,667 79.14 ----------- ---------- ---------- --------- ---------- --------- Gross margin........................... 57,154 37.18 25,319 63.86 109,277 20.86 ----------- ---------- ---------- --------- ---------- --------- Administrative and general costs....... 9,114 5.93 10,475 26.42 8,636 1.65 Energy production costs................ 184 0.12 493 1.24 35,547 6.78 Depreciation and amortization.......... 8,220 5.35 5,400 13.62 10,565 2.02 Transmission and distribution costs.... 10,180 6.62 8,125 20.49 97 0.02 Taxes other than income taxes.......... 2,867 1.87 1,338 3.37 2,367 0.45 Income taxes........................... 8,305 5.40 (1,162) (2.93) 18,842 3.60 ----------- ---------- ---------- --------- ---------- --------- Total non-fuel operating expenses.... 38,870 25.29 24,669 62.22 76,054 14.52 ----------- ---------- ---------- --------- ---------- --------- Operating income....................... $18,284 11.89% $ 650 1.64% $ 33,223 6.34% ----------- ---------- ---------- --------- ---------- ---------
34 Three Months Ended September 30, 2000
Utility -------------------------------------------- Generation Electric Gas and Trading --------------------- ---------------------- -------------------- Operating revenues: External customers................... $149,970 99.88% $ 55,133 100.00% $ 294,131 76.44% Intersegment revenues................ 177 0.12 - 0.00 90,638 23.56 ---------- --------- ---------- ---------- ----------- -------- Total revenues....................... 150,147 100.00 55,133 100.00 384,769 100.00 ---------- --------- ---------- ---------- ----------- -------- Cost of energy sold.................... 1,442 0.96 30,776 55.82 284,301 73.89 Intersegment purchases................. 90,638 60.37 - 0.00 177 0.05 ---------- --------- ---------- ---------- ----------- -------- Total fuel costs..................... 92,080 61.33 30,776 55.82 284,478 73.93 ---------- --------- ---------- ---------- ----------- -------- Gross margin........................... 58,067 38.67 24,357 44.18 100,291 26.07 ---------- --------- ---------- ---------- ----------- -------- Administrative and general costs....... 9,787 6.52 8,279 15.02 9,585 2.49 Energy production costs................ 296 0.20 328 0.59 32,230 8.38 Depreciation and amortization.......... 7,856 5.23 4,990 9.05 10,170 2.64 Transmission and distribution costs.... 8,519 5.67 6,020 10.92 (1) 0.00 Taxes other than income taxes.......... 2,938 1.96 1,614 2.93 2,216 0.58 Income taxes........................... 9,569 6.37 263 0.48 13,771 3.58 ---------- --------- ---------- ---------- ----------- -------- Total non-fuel operating expenses.... 38,975 25.96 21,494 38.99 67,970 17.67 ---------- --------- ---------- ---------- ----------- -------- Operating income....................... $19,092 12.72% $ 2,863 5.19% $ 32,321 8.40% ---------- --------- ---------- ---------- ----------- --------
UTILITY OPERATIONS Electric - Operating revenues increased $3.6 million (2.4%) for the period to $153.7 million primarily due to an increase in transmission wheeling revenues of $3.1 million as a result of additional capacity sales. Retail electricity delivery grew 2.4% to 2.02 million MWh in 2001 compared to 1.98 million MWh delivered in the prior year period. This volume increase was the result of normal load growth. The gross margin, or operating revenues minus cost of energy sold, decreased $0.9 million reflecting an increase in intersegment transfer pricing, partially offset by the increase in transmission wheeling revenues. Gross margin as a percentage of revenues declined from 38.7% to 37.1%. The decline in gross margin percentage is primarily a result of the increase in intersegment transfer pricing. The Company's Generation and Trading Operations exclusively provide power to Electric. Intersegment purchases from the Generation and Trading Operations are priced using internally developed transfer pricing and are not based on market rates. Customer rates for electric service are set by the PRC based on the recovery of the cost of power production and a rate of return that includes certain generation assets that are part of Generation and Trading Operations, among other things. Administrative and general costs decreased $0.7 million (7.0%) primarily due to lower bad debt expense, partially offset by consulting expenses in connection with cost control and process improvement initiatives. By 2001, the Company had resolved most of the problems associated with the implementation of its new billing system (see "Other Issues Facing the Company - Implementation of New Customer Billing System.") As a result, bad debt expense was significantly lower in 2001. As a percentage of revenues, administrative and general costs decreased to 5.9% from 6.5% for the three months ended September 30, 2001 and 2000, respectively as a result of the decrease in costs. 35 Transmission and distribution costs increased $1.7 million (19.5%) primarily as a result of a non-recurring increase in maintenance to improve reliability for the transmission and distribution systems. These increased expenses are not expected to continue into 2002. Transmission and distribution costs as a percentage of revenues increased from 5.7% to 6.6 % due to the increase in costs. Gas - Operating revenues decreased $15.5 million (28.1%) for the period to $39.6 million. This decrease was driven by a 28.8% decrease in the average rate charge per decatherm due to lower market prices for natural gas in the third quarter of 2001 and a 3.8% volume decrease. As a result of a weak wholesale electricity market in the third quarter, demand for natural gas decreased significantly. These declines were partially offset by a gas rate increase which became effective October 30, 2000. Industrial customer volume decreased 93.8% and revenues decreased $11.1 million. This decline was primarily attributed to the Company's Generation and Trading Operations due to weak wholesale market pricing. In the second quarter of 2001, the Company's Generation and Trading Operations began procuring its gas supply independent of the Company and contracting with the Utility Operations for transportation services only. Residential and commercial customers volume increased 6.8%; however, due to the lower prices, revenues decreased $3.2 million. These decreases were partially offset by an increase in transportation volume of 13.0% and revenues of $2.4 million. The Company does not earn cost of service revenues on transportation customers. The gross margin, or operating revenues minus cost of energy sold, increased $1.0 million (3.9%). This increase is due to the rate increase and higher off-system transportation volumes partially offset by the decrease in volumes. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, the change in gas prices driving cost of sales revenues does not have an impact on the Company's gross margin or earnings. Administrative and general costs increased $2.2 million (26.5%). This increase is due to additional customer service expense for increased collection activities. The significantly higher natural gas prices experienced during the 2000-2001 heating season resulted in higher than normal delinquency rates. In addition, the Company incurred certain consulting expenses in connection with its cost control initiatives. Depreciation and amortization increased $0.4 million (8.2%) for the period due to additions to the depreciable plant base. Transmission and distribution costs increased $2.1 million (35.0%) as a result of a one-time increase in maintenance to improve reliability for the transportation and distribution systems. These increased expenses are not expected to continue into 2002. GENERATION AND TRADING OPERATIONS Operating revenues grew $139.2 million (36.2%) for the period to $523.9 million. This increase in wholesale electricity sales primarily reflects higher regional wholesale electric prices. However, prices have been declining since the end of the second quarter of 2001 (see below). The Company delivered wholesale (bulk) power of 3.5 million MWh of electricity this period compared to 3.3 million MWh delivered in the prior period, an increase of 6.8%. The MWh increase is attributable to increased wholesale trading activity during the period. 36 The strong wholesale electric prices experienced in the second half of 2000 and the first half of 2001 were caused by limited power generation capacity, increased natural gas prices and the power supply/demand imbalance in the Western United States. The wholesale electric and natural gas markets experienced falling price levels at the end of the second quarter of 2001, which continued through the third quarter of 2001. These price declines were due to California conservation measures, moderate weather, the economic slowdown and FERC price caps (see "Western United States Wholesale Power Market"). Since the end of the second quarter, prices have declined significantly, and liquidity in the market place - the opportunity to buy/resell power - declined as trading activity slowed (see "Other Issues Facing the Company - Western United States Wholesale Power Market"). If these trends continue, the Company expects operating revenues from wholesale trading activities to continue to decline in the fourth quarter of 2001 (see "Future Expectations"). The majority of the wholesale sales are from power purchased for resale. Exposure to adverse market moves is limited through an asset backed strategy, whereby the Company's aggregate net open position is covered by its generation resources, primarily generation which has been excluded from retail rates. This strategy, along with the Company's credit policies, limits the Company's wholesale sales in a volatile market. Wholesale revenues from third-party customers increased from $294.1 million to $428.5 million, a 45.7% increase. The increase was largely price driven. The gross margin, or operating revenues minus cost of energy sold, increased $9.0 million (9.0%). Gross margin as a percentage of revenues decreased from 26.1% to 20.9% reflecting increased prices for purchased power for resale and increased purchases due to an unscheduled outage at San Juan. A $4.6 million reduction in the Company's allowances for market price volatility and credit risk in the wholesale power market, as a result of the falling prices in the third quarter, contributed to the increase in gross margin (see "Other Issues Facing The Company - Western United States Wholesale Power Market"). In addition, the Company recorded unrealized mark-to-market losses of $0.6 million relating to its power trading contracts in the third quarter of 2001. In 2000, the Company recognized a $12.1 unrealized gain relating to its power trading contracts (see Note 4 of the Notes to Consolidated Financial Statements). These items were recorded as revenue adjustments. Administrative and general costs decreased $0.9 million (9.9%) for the period. This decrease is primarily due to business development costs in the prior year, which did not reoccur in 2001, of $4.5 million related to the acquisition of a long-term wholesale customer. This decrease is offset by higher power marketing expenses resulting from increased incentive bonuses and certain business development related consulting fees. In addition, decreased capital activity resulted in a smaller portion of overhead costs being allocated to capital projects. As a percentage of revenues, administrative and general costs decreased to 1.7% from 2.5% for the three months ended September 30, 2001 and 2000, respectively as a result of increased revenues and decreased costs. Energy production costs increased $3.3 million (10.3%) for the period. The increase is primarily due to higher maintenance costs in 2001 resulting from an unscheduled outage at San Juan Unit 3. As a percentage of revenues, energy production costs decreased from 8.4% to 6.8%. The decrease is primarily due to the significant increase in revenues. 37 UNREGULATED BUSINESSES Due to the cessation of much of Avistar's historic operations, business activity declined significantly (see "Overview - Avistar"). Revenues decreased 25.9% for the period. Operating losses for Avistar decreased from $1.3 million in the prior year period to $0.7 million in the current year period primarily due to decreased business activity. CONSOLIDATED Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, increased $2.8 million for the period from $6.9 million to $9.7 million. This increase was due to higher legal costs, expenses related to business development and an increase in bonus accruals reflecting the Company's earnings profile for 2001. Corporate taxes other than income decreased $2.5 million due to higher tax liabilities in the prior year period as a result of favorable audit outcomes by certain tax authorities and tax planning strategies. Other income and deductions, net of taxes, decreased $14.5 million for the period to income of $1.0 million primarily due to certain gains recognized in 2000 which did not reoccur in 2001. In 2000, the Company recognized gains of $13.8 million (pre-tax) related to the settlement of a lawsuit and $4.6 million (pre-tax) for the reversal of certain reserves associated with the expected resolution of two gas rate cases. In the third quarter of 2001, the Company recorded a charge of $4.2 million (pre-tax) to write-off an investment by Avistar in a technology Company which was impaired. The current period also had mark-to-market losses of $0.9 million (pre-tax) on the PVNGS decommissioning trust assets compared to mark-to-market gains of $0.8 million (pre-tax) in the prior year period (see Note 4 to the Consolidated Financial Statements) and increased costs of $0.9 million (pre-tax) related to the Company's proposed acquisition of Western Resources' electric utility operations. Total costs for the third quarter 2001 related to the Company's proposed acquisition of Western Resources were $3.4 million (pre-tax). Recently, certain developments have led the Company to conclude the acquisition cannot be accomplished under the terms of the present acquisition agreement (see "Other Issues Facing the Company - Proposed Acquisition of Western Resources Electric Operations" below). The Company's consolidated income tax expense was $22.3 million in the three months ended September 30, 2001, a decrease of $7.5 million for the period. The Company's income tax effective rate for the three months ended September 30, 2001 was 40.54% compared to 38.84% for the three months ended September 30, 2000. Included in the Company's 2001 and 2000 taxable income are certain non-deductible costs related to the Company's acquisition of Western Resources' electric utility operations. Excluding the impact of these costs, the Company's effective tax rate declined to 38.76% for 2001 compared to 38.87% for 2000. The Company's net earnings for the three months ended September 30, 2001 were $32.8 million, a 30.1% decrease. Excluding the Western Resources' acquisition costs and the related impact on the effective tax rate and the 38 write-off of the Avistar investment ("2001 Special Items"), the Company's net earnings were $38.4 million. Net earnings for the three months ended September 30, 2000 were $46.9 million. Excluding the gains for the lawsuit settlement and the reversal of certain gas rate case reserves, the charge in connection with the acquisition of a long-term wholesale customer and the Western Resources' acquisition costs and the related impact on the effective tax rate ("2000 Special Items"), the Company's net earnings were $40.0 million. Earnings per share on a diluted basis were $0.96 (excluding the 2001 Special Items) for the three months ended September 30, 2001 compared to $1.01 (excluding the 2000 Special Items) for the three months ended September 30, 2000. Diluted weighted average shares outstanding were remained constant at 39.7 million in 2001 and 2000. Net earnings per share from continuing operations primarily decreased due to a decline in utility operating income. Nine Months Ended September 30, 2001 Compared to Nine Months Ended September 30, 2000 The table below sets forth the operating results as percentages of total operating revenues for each business segment.
Nine Months Ended September 30, 2001 Utility ------------------------------------------- Generation Electric Gas and Trading ----------------------- ------------------- ---------------------- Operating revenues: External customers................... $424,249 99.88% $318,670 100.00% $1,280,141 83.13% Intersegment revenues................ 530 0.12 - 0.00 259,726 16.87 ----------- ---------- --------- --------- ----------- --------- Total revenues....................... 424,779 100.00 318,670 100.00 1,539,867 100.00 ----------- ---------- --------- --------- ----------- --------- Cost of energy sold.................... 3,957 0.93 220,547 69.21 1,136,400 73.80 Intersegment purchases................. 259,726 61.14 - 0.00 530 0.03 ----------- ---------- --------- --------- ----------- --------- Total fuel costs..................... 263,683 62.08 220,547 69.21 1,136,930 73.83 ----------- ---------- --------- --------- ----------- --------- Gross margin........................... 161,096 37.92 98,123 30.79 402,937 26.17 ----------- ---------- --------- --------- ----------- --------- Administrative and general costs....... 29,660 6.98 34,162 10.72 20,296 1.32 Energy production costs................ 687 0.16 1,306 0.41 107,135 6.96 Depreciation and amortization.......... 24,311 5.72 16,023 5.03 31,981 2.08 Transmission and distribution costs.... 26,621 6.27 21,829 6.85 310 0.02 Taxes other than income taxes.......... 8,527 2.01 4,989 1.57 6,611 0.43 Income taxes........................... 22,616 5.32 4,532 1.42 84,698 5.50 ----------- ---------- --------- --------- ----------- --------- Total non-fuel operating expenses.... 112,422 26.47 82,841 26.00 251,031 16.30 ----------- ---------- --------- --------- ----------- --------- Operating income....................... $48,674 11.46% $15,282 4.80% $ 151,906 9.86% ----------- ---------- --------- --------- ----------- ---------
39 Nine Months Ended September 30, 2000
Utility -------------------------------------------- Generation Electric Gas and Trading --------------------- ---------------------- -------------------- Operating revenues: External customers..................... $406,034 99.87% $ 204,193 100.00% $537,647 68.67% Intersegment revenues.................. 530 0.13 - 0.00 245,330 31.33 ---------- --------- ---------- ---------- ---------- --------- Total revenues......................... 406,564 100.00 204,193 100.00 782,977 100.00 ---------- --------- ---------- ---------- ---------- --------- Cost of energy sold...................... 3,707 0.91 118,706 58.13 542,223 69.25 Intersegment purchases................... 245,330 60.34 - 0.00 530 0.07 ---------- --------- ---------- ---------- ---------- --------- Total fuel costs....................... 249,037 61.25 118,706 58.13 542,753 69.32 ---------- --------- ---------- ---------- ---------- --------- Gross margin............................. 157,527 38.75 85,487 41.87 240,224 30.68 ---------- --------- ---------- ---------- ---------- --------- Administrative and general costs......... 27,299 6.71 27,585 13.51 18,279 2.33 Energy production costs.................. 924 0.23 1,117 0.55 102,361 13.07 Depreciation and amortization............ 23,903 5.88 14,870 7.28 30,873 3.94 Transmission and distribution costs...... 24,385 6.00 20,198 9.89 23 0.00 Taxes other than income taxes............ 9,433 2.32 5,422 2.66 7,550 0.96 Income taxes............................. 22,854 5.62 3,353 1.64 18,529 2.37 ---------- --------- ---------- ---------- ---------- --------- Total non-fuel operating expenses...... 108,798 26.76 72,545 35.53 177,614 22.68 ---------- --------- ---------- ---------- ---------- --------- Operating income......................... $48,729 11.99% $ 12,942 6.34% $ 62,610 8.00% ---------- --------- ---------- ---------- ---------- ---------
UTILITY OPERATIONS Electric - Operating revenues increased $18.2 million (4.5%) for the period to $424.8 million. Retail electricity delivery grew 3.0% to 5.52 million MWh in 2001 compared to 5.36 million MWh delivered in the prior year period, resulting in increased revenues of $8.3 million period-over-period. This volume increase was the result of both a weather-driven increase in consumption and load growth. In addition, transmission wheeling revenues increased $8.1 million as a result of additional capacity sales not likely to recur in 2002 and other revenues increased $1.8 million primarily for new property leasing for telecommunication systems. The gross margin, or operating revenues minus cost of energy sold, increased $3.6 million but declined slightly as a percentage of revenues. This dollar increase reflects the increased energy sales, transmission wheeling revenues and the telecommunication property leasing, partially offset by an increase in intersegment transfer pricing. Gross margin as a percentage of revenues declined from 38.8% to 37.9%. The decline in gross margin percentage is primarily a result of the increase in intersegment transfer pricing. The Company's Generation and Trading Operations exclusively provide power to Electric. Intersegment purchases from the Generation and Trading Operations are priced using internally developed transfer pricing and are not based on market rates. Customer rates for electric service are set by the PRC based on the recovery of the cost of power production and a rate of return that includes certain generation assets that are part of Generation and Trading Operations, among other things. Administrative and general costs increased $2.4 million (8.6%) for the period. This increase is primarily due to increased pension and benefits expense resulting primarily from lower than expected investment returns on related plan assets and consulting expenses in connection with cost control and process improvement initiatives. These increases were partially offset by lower bad debt 40 expense. By December 2000, the Company had resolved most of the problems associated with the implementation of its new billing system (see "Other Issues Facing the Company - Implementation of New Customer Billing System"). As a result bad debt expense was significantly lower in 2001. As a percentage of revenues, administrative and general costs increased to 7.0% from 6.7% for the nine months ended September 30, 2001 and 2000, respectively, primarily as a result of the increased pension and benefits costs. Transmission and distribution costs increased $2.2 million (9.2%) primarily due to a non-recurring increase in maintenance to improve reliability for the transmission and distribution systems. These expenses are not expected to continue in 2002. Transmission and distribution costs as a percentage of revenues increased to 6.3% from 6.0% for the nine months ended September 30, 2001 and 2000, respectively due to the increased costs. Taxes other than income decreased $0.9 million (9.6%) due to higher tax liabilities in the prior year period as a result of favorable audit outcomes by certain tax authorities and tax planning strategies. Taxes other than income as a percentage of revenues decreased to 2.0% from 2.3%. Gas - Operating revenues increased $114.5 million (56.1%) for the period to $318.7 million. This increase was driven by a 42.7% increase in the average rate charge per decatherm due to high wholesale gas prices in 2001 resulting from increased market demand, a 10.3% volume increase and a gas rate increase, which became effective October 30, 2000. Residential and commercial customers volume increased 9.9% due to a colder winter during 2001. Customer volume, other than residential and commercial, increased 10.4%. This growth was primarily attributed to transportation and industrial customers such as the Company's Generation and Trading Operations whose increased demand was driven by the strong power market in the Western United States during 2001. This increase is not expected to recur in 2002. In the second quarter of 2001, the Company's Generation and Trading Operations began procuring its gas supply independent of the Company and contracting with the Utility Operations for transportation services only. The Company does not earn cost of service revenues on transportation customers. The gross margin, or operating revenues minus cost of energy sold, increased $12.6 million (14.8%). This increase is due to the rate increase, higher distribution volumes on which the Company earns cost of service revenues and higher off-system transportation volumes, which will likely not recur in 2002. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, the increase in gas prices driving increased cost of sales revenues does not have an impact on the Company's gross margin or earnings. Administrative and general costs increased $6.6 million (23.8%). This increase is due to increased pension and benefits expense resulting primarily from lower than expected investment returns on related plan assets, consulting expenses in connection with cost control and process improvement initiatives and increased bad debt and collection costs. The significantly higher natural gas prices experienced during the 2000-2001 heating season resulted in higher than normal delinquency rates. This trend is similar to historic collection trends and patterns associated with past natural gas price spikes. Depreciation and amortization increased $1.2 million (7.8%) for the period due to a higher depreciable plant base. 41 Transmission and distribution costs increased $1.6 million (8.1%) primarily due to increased maintenance to improve reliability for the transmission and distribution systems. These increased expenses are not expected to continue in 2002. GENERATION AND TRADING OPERATIONS Operating revenues grew $756.9 million (96.7%) for the period to $1.5 billion. This increase in wholesale electricity sales primarily reflects continued strong regional wholesale electric prices. However, prices have been declining since the end of the second quarter of 2001 (see below). The Company delivered wholesale (bulk) power of 9.8 million MWh of electricity this period, compared to 9.6 million MWh in the prior period. The strong wholesale electric prices were caused by limited power generation capacity, increased natural gas prices and the power supply/demand imbalance in the Western United States. These factors contributed to unusually high wholesale prices in the second half of 2000 and most of 2001, which the Company does not believe will recur in 2002. At the end of the second quarter of 2001, the market experienced falling price levels. This trend continued in the third quarter of 2001. Since the end of the second quarter, wholesale electricity prices have declined significantly, and liquidity - the opportunity to buy and resell power - in the market place has also declined as trading activity has slowed (see "Other Issues Facing the Company - Western United States Wholesale Power Market"). If these trends continue, the Company expects operating revenues to decline in the fourth quarter of 2001 (see - "Future Expectations"). The Company also believes that current weak market pricing is not sustainable and that prices will adjust to more normal historical levels in 2002. The majority of the wholesale sales are from power purchased for resale. Exposure to adverse market moves is limited through an asset backed strategy, whereby the Company's aggregate net open position is covered by its generation resources, primarily generation which has been excluded from retail rates. This strategy, along with the Company's risk management and credit policies, limits the Company's wholesale sales in a volatile market. Wholesale revenues from third-party customers increased from $537.6 million to $1.3 billion, a 138.1% increase. The increase was largely price driven. The gross margin, or operating revenues minus cost of energy sold, increased $162.7 million (67.7%). Gross margin as a percentage of revenues decreased from 30.7% to 26.2% reflecting increased prices for purchased power for resale. Higher margins were partially offset by unrealized mark-to-market losses of $24.9 million which the Company recognized relating to its power trading contracts (see Note 4 of the Notes to Consolidated Financial Statements). This mark-to-market adjustment is due to the significant decline in electric prices at the end of the second quarter. In 2000, the Company recognized a $1.7 million unrealized loss resulting to its power trading contracts (see Note 4 of the Notes to Consolidated Financial Statements). In addition, the Company recorded $2.1 million of allowances for market and credit risk in the wholesale power market (see "Other Issues Facing The Company - Western United States Wholesale Power Market"). These items were recorded as revenue adjustments. Administrative and general costs increased $2.0 million (11.0%) for the period. This increase is primarily due to increased pension and benefits expense, higher power marketing expenses mainly for additional incentive bonuses and certain consulting fees and other expenses related to business development and process improvement. In the prior year, Generation and Trading recognized 42 business development costs of $4.5 million related to the acquisition of a long-term wholesale customer. As a percentage of revenues, administrative and general costs decreased to 1.3% from 2.3% for the nine months ended September 30, 2001 and 2000, respectively as a result of increased wholesale revenues. Energy production costs increased $4.8 million (4.7%) for the year. The increase is primarily due to higher maintenance costs in 2001 resulting from scheduled and unscheduled outages at San Juan Unit 3, additional incentive bonuses at San Juan, and increased generation at Reeves, one of the Company's gas generation facilities, which has a higher cost of production than its coal and nuclear facilities. This increase was partially offset by lower maintenance costs at Four Corners as a result of decreased outage time. As a percentage of revenues, energy production costs decreased from 13.1% to 7.0%. The decrease is primarily due to the significant increase in wholesale revenues. Depreciation and amortization increased $1.1 million (3.6%) for the period due to a higher depreciable plant base. Depreciation and amortization as a percentage of revenues decreased from 3.9% to 2.1% due to the increase in wholesale revenues. Taxes other than income decreased $0.9 million (12.4%) due to higher tax liabilities in the prior year period as a result of favorable audit outcomes by certain tax authorities and tax planning strategies. Taxes other than income as a percentage of revenues decreased from 1.0% to 0.4% as a result of the increase in wholesale revenues. UNREGULATED BUSINESSES Due to the cessation of much of Avistar's historic operations, business activity declined significantly (see "Overview - Avistar"). Revenues decreased 24.8% for the period. Operating losses for Avistar increased from $3.3 million in the prior year period to $3.5 million in the current year period primarily due to increased costs related to the shutdown of certain operations. CONSOLIDATED Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, increased $4.0 million for the period. This increase was due to additional bonus expense as a result of increased earnings, partially offset by lower legal costs associated with routine business operations and reorganizational costs incurred in 2000 that did not occur in 2000 due to the legislative mandated delay in separating utility operations under the Restructuring Act (see "Restructuring The Electric Utility Industry"). Other income and deductions, net of taxes, decreased $40.7 million for the period to a loss of $10.9 million primarily due to certain gains recognized in 2000, which did not reoccur in 2001 and certain write-off's in 2001. In 2000, the Company recognized gains of $13.8 million (pre-tax) related to the settlement of a lawsuit, $4.5 million (pre-tax) for the reversal of certain reserves associated with the expected resolution of two gas rate cases and $2.4 million (pre-tax) related to the Company's hedge of certain non-qualified retirement plan trust assets. In the current year, the Company recorded charges of $13.1 million (pre-tax) to write-off certain Avistar investments, which were 43 permanently impaired (see "Overview - Avistar"). In addition in 2001, the Company recognized the write-off of $13.0 million (pre-tax) of non-recoverable coal mine decommissioning costs previously established as a regulatory asset. As a result of the Company's evaluation of its regulatory strategy in light of the holding company filing in May 2001, management determined that it would not seek recovery of a portion of its previously established stranded cost asset. The remaining portion of costs associated with coal mine decommissioning that are attributed to local jurisdictional customers will be sought in future rate cases. As a result, the Company will continue to evaluate the recoverability of such cost as the rate making process occurs. In addition, the Company will identify its stranded cost as separation nears. The current year results also include a donation of $5.0 million (pre-tax) to the PNM Foundation, unrecoverable costs of $2.3 million (pre-tax) related to a failed transmission line, mark-to-market losses of $2.7 million (pre-tax) on the PVNGS decommissioning trust assets compared to mark-to-market gains of $2.6 million (pre-tax) in the prior year (see Note 4 to the Consolidated Financial Statements) and increased costs of $5.5 million (pre-tax) related to the Company's proposed acquisition of Western Resources' electric utility operations. Total costs for the nine months ended September 30, 2001 related to the Company's proposed acquisition of Western Resources were $8.0 million (pre-tax). Recently, certain developments have led the Company to conclude the acquisition cannot be accomplished under the terms of the present acquisition agreement (see "Other Issues Facing the Company - Proposed Acquisition of Western Resources Electric Operations" below). The Company has expensed all costs related to the acquisition to date. The Company's consolidated income tax expense was $85.9 million in the nine months ended September 30, 2001, an increase of $33.7 million for the period. The Company's income tax effective rate for the nine months ended September 30, 2001 was 37.06%. Included in the Company's 2001 taxable income are certain non-deductible costs related to the Company's proposed acquisition of Western Resources' electric utility operations and the reversal of $6.6 million of allowances taken against certain income tax related regulatory assets in 2000 as a result of the Company's evaluation of its regulatory strategy in light of the holding company filing in May 2001. In 2000, management believed these income tax related regulatory assets would not be recoverable based on the probable financial outcome of industry restructuring in New Mexico. The charge to earnings in 2000, related to these assets, reflected management's view of the probable financial outcome of industry restructuring in New Mexico, based on discussions occurring between the Company and the PRC staff at that time. Currently, management fully expects to recover these costs in future rate cases. Excluding the impact of these items, the Company's effective tax rate for 2001 was 38.88%. The Company's effective tax rate for the nine months ended September 30, 2000 was 37.53%. The Company's 2000 taxable income also includes certain non-deductible costs related to the Company's proposed acquisition of Western Resources' electric utility operations. Excluding the impact of these costs, the Company's effective tax rate for 2000 was 37.57%. The increase in the effective rate was primarily due to an increase in the depreciation of flow through items. The Company's net earnings for the nine months ended September 30, 2001 were $145.9 million, a 68.0% increase. Excluding the write-off of coal mine decommissioning costs, the donation to the PNM Foundation, the charges related to Avistar and the Western Resources' acquisition costs and the related impact on the effective tax rate ("2001 Special Items"), the Company's net earnings in 44 2001 were $171.9 million. Net earnings for the nine months ended September 30, 2000 were $86.9 million. Excluding the gains for the lawsuit settlement, the reversal of certain gas rate case reserves, the charge in connection to the acquisition of a long-term wholesale customer, the charges related to the Western Resources' acquisition costs and the related impact on the effective tax rate ("2000 Special Items"), the Company's net earnings in 2000 were $80.0 million. Earnings per share on a diluted basis were $4.31 (excluding the 2001 Special Items) for the nine months ended September 30, 2001 compared to $2.00 (excluding the 2000 Special Items) for the nine months ended September 30, 2000. Diluted weighted average shares outstanding were 39.8 million in 2001 and 39.7 million in 2000. Net earnings per share from continuing operations primarily increased due to the increased operating income from the Company's Generation and Trading Operations. FUTURE EXPECTATIONS On October 24, 2001, the Company announced that it expects full year 2001 earnings to be at least $4.50 per share. While forecasting a substantial increase in earnings for 2001, management does not believe those gains will recur in 2002 and beyond. As conservation measures take effect in California and throughout the west, and as new generation comes on-line over the next two to three years, management expects that prices will stabilize at somewhat lower levels. In addition, on June 19, 2001, the FERC mandated its price mitigation plan. Wholesale electricity prices have decreased significantly and liquidity in the market place has also declined as trading activity has slowed. Since a reduced pricing environment is likely to have a negative impact on the funding new generation, the Company would expect that forward prices would again trend upwards in future periods. Looking forward to 2002, management believes that its sustainable earnings per share are in a range of $3.00 to $3.50. This expectation is based on management's view of the Western United States wholesale power market and the Company's power market positioning and base earnings ability. It also assumes the FERC price caps will not be decreased further and will be lifted as scheduled. The high end of the 2002 sustainable earnings range assumes 2002 Western United States wholesale power market prices will be in the range of $45 per MWh. This assumed price is above forward prices for 2002 as of October 24, 2001. The impact of wholesale electricity price movement on expected earnings per share amount is difficult to project. The calculation is subject to numerous variables, including but not limited to, on and off-peak wholesale demand, retail load needs, natural gas prices, the current position of the Company's trading portfolio and general economic conditions. If average wholesale prices were to decrease to $30 per MWh (the current forward price), management believes sustainable earnings to be around $3.00 per share. As the Company adds new generation resources, it is expected that earnings will trend upwards as sales volumes grow. This growth is expected to be in high single digits, a rate less than the 10 percent annual growth rate previously targeted by management due to the higher base earnings the Company has forecasted. The Company's strategic plan to add generation resources will provide electric wholesale volume growth beginning in 2002 and in the later years of the forecast. These expectations are all stand-alone forecasts and do not take into account any impact of the proposed acquisition of Western Resources. 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 45 the preceding discussion, and is qualified in its entirety by the Private Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding Forward Looking Statements" below) - and the factors described within the disclosure which could cause the Company's actual financial results to differ materially from the expected results enumerated above. LIQUIDITY AND CAPITAL RESOURCES At September 30, 2001, the Company had working capital of $182.4 million including cash and cash equivalents of $222.6 million. This is an increase in working capital of $34.6 million from December 31, 2000. This increase primarily reflects increased cash receipts related to the Company's activity in the wholesale power market. Cash generated from operating activities in the nine months ended September 30, 2001 was $296.9 million, an increase of $126.6 million from 2000. This increase was primarily the result of increased profitability. Contributing to this increase was the timing of payments for purchased power, the recovery of purchased gas adjustments from utility customers and a decrease in utility customer accounts receivable primarily as a result of seasonal volume declines. Also, the increase in wholesale accounts receivable was lower than the prior year increase. In addition, the Company did not make the first quarter 2001 estimated federal income tax payment because of an automatic extension granted by the IRS to taxpayers in several counties in New Mexico as a result of wildfires in 2000. This payment is due January 2002. Improved operating cash flows have driven the Company's cash balance up to $286.1 million from $107.7 million at December 31, 2000. Cash used for investing activities was $153.9 million in 2001 compared to $86.7 million in 2000. This increased spending reflects combustion turbine progress payments of $68.0 million in 2001 compared to $21.4 million in 2000 and $7.5 million related to the acquisition of certain transmission assets. Cash used for financing activities was $28.1 million compared to $85.5 million in 2000. Cash used for financing activities in 2001 was primarily for dividend requirements. The decrease in cash used for financing activities from 2000 to 2001 reflects the 2000 repurchase of $34.7 million of senior unsecured notes at a cost of $32.8 million and common stock repurchases in 2000 (see "Stock Repurchase" below). Capital Requirements Total capital requirements include construction expenditures as well as other major capital requirements and cash dividend requirements for both common and preferred stock. The main focus of the Company's construction program is upgrading generation systems, upgrading and expanding the electric and gas transmission and distribution systems and purchasing nuclear fuel. In addition, the Company anticipates significant expenditures to expand its wholesale generation capabilities. Projections for total capital requirements and construction expenditures for 2001 are $370 million and $353 million, respectively. Such projections for the years 2001 through 2005 are $1.52 billion and $1.45 billion, respectively. These estimates are under continuing review and subject to on-going adjustment (see "Competitive Strategy" above). The Company has committed to purchase five combustion turbines totaling $151.3 million. The turbines are for three planned power generation plants with 46 a combined capacity of 657 MWs. The plants estimated cost of construction is approximately $400.3 million. The Company has expended $89.4 million as of September 30, 2001. In November, 2001, the Company plans to break ground for a new 135 MW single cycle gas turbine plant on a site in Southern New Mexico. Currently the Company plans to expand the facility to 540 MW by 2003. Contracts have not been finalized on the remaining planned construction. The planned plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. Such construction is not anticipated to be added to the rate base. The Company's construction expenditures for 2001 were entirely funded through cash generated from operations. The Company currently anticipates that internal cash generation and current debt capacity will be sufficient to meet capital requirements for the years 2001 through 2005. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under its liquidity arrangements. Liquidity At November 1, 2001, the Company had $170 million of available liquidity arrangements, consisting of $150 million from a senior unsecured revolving credit facility ("Credit Facility"), and $20 million in local lines of credit. The Credit Facility will expire in March 2003. There were no outstanding borrowings as of November 1, 2001. The Company's ability to finance its construction program at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, results of operations, credit ratings, regulatory approvals and financial 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. In connection with the Company's announcement of its proposed acquisition of Western Resources' electric utility operations, Standard and Poors ("S&P"), Moody's Investor Services ("Moody's") and Fitch IBCA, Duff & Phelps ("Fitch") have placed the Company's securities ratings on negative credit watch pending review of the transaction. On October 19, 2001, S&P removed the Company from negative credit watch. The Company is committed to maintaining its investment grade. S&P currently rates the Company's senior unsecured notes ("SUNs") and its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its preferred stock "BB". Moody's rates the Company's SUNs and senior unsecured pollution control revenue bonds "Baa3"; and preferred stock "ba1". The EIP senior secured debt are also rated "Ba1". Fitch rates the Company's SUNs and senior unsecured pollution control revenue bonds "BBB-," the Company's EIP lease obligation "BB+" and the Company's preferred stock "BB-." Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it may be subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating. Covenants in the Company's PVNGS Units 1 and 2 lease agreements limit the Company's ability, without consent of the owner participants in the lease transactions: (i) to enter into any merger or consolidation, or (ii) except in 47 connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. The Credit Facility imposes similar restrictions regardless of credit ratings. Financing Activities The Company currently has no maturities of long-term financings during the period of 2001 through 2005. However, during this period, the Company could enter into long-term financings for the purpose of strengthening its balance sheet, funding growth and reducing its cost of capital. The Company continues to evaluate its investment and debt retirement options to optimize its financing strategy and earnings potential. No additional first mortgage bonds may be issued under the Company's mortgage. The amount of SUNs that may be issued is not limited by the SUNs indenture. However, debt to capital requirements in certain of the Company's financial instruments would ultimately restrict the Company's ability to issue SUNs. Proposed Holding Company Plan Previously, the Company provided details of its proposed holding company plan as contemplated in response to the implementation dates established under the Restructuring Act before it was amended in March of 2001 (see "Restructuring of the Electric Utility Industry" above). As a result of the amendments to the Restructuring Act delaying customer choice and corporate restructuring for five years, the Company has modified its previously reported holding company plan. Currently, the Company plans to implement a holding company structure on December 1, 2001, as permitted under the amended Restructuring Act, without corporate separation of supply service and energy-related services assets from distribution and transmission services assets. This structure provides for a holding company whose current holdings will be the Company, Avistar and other inactive unregulated subsidiaries. This is expected to be effected through a share exchange between current company shareholders and the proposed holding company, PNM Resources, which is currently a wholly-owned subsidiary of the Company. Avistar and the other inactive unregulated subsidiaries are expected to become wholly-owned subsidiaries of the holding company. The transfer of the subsidiaries and certain assets to the holding company is subject to receipt of an additional order from the PRC, which may not be received until after formation of the holding company through the mandatory share exchange. There are no current plans to provide the proposed holding company with significant debt financing. The Company is unable to predict the form its further restructuring will take under the delayed implementation of customer choice. The PRC issued an order approving formation of a holding company on June 28, 2001. The order limits the Company's proposed utility subsidiary's ability to pay dividends to the parent holding company, without prior PRC approval, to annual current earnings determined on a rolling four quarter basis and imposes certain regulatory requirements regarding merchant generation plants. The Company believes that certain conditions imposed by the PRC order are unlawful and could have an adverse effect on the Company's ability to execute its growth strategy. On July 27, 2001, the Company asked the PRC to reconsider certain conditions imposed by the order. The PRC did not act on the Company's request, and the request was deemed denied on August 16, 2001. Despite this adverse 48 ruling, the Company plans to proceed with its plans to activate PNM Resources and complete the mandatory share exchange. At the same time, the Company will continue with its efforts to minimize the adverse effects of the order. On September 14, 2001, the Company asked the New Mexico Supreme Court to review the holding company order. The Company believes the PRC exceeded its jurisdiction and placed certain conditions on the new corporate structure that the Company believes are unlawful. The Attorney General has filed a cross-appeal. The Company is unable to predict the outcome of its appeal or the cross-appeal. In filings with the PRC, Staff and other parties have raised the issue whether the Company can form the holding company pending appeal. The Company has filed its response and intends to vigorously defend its right to form the holding company pending appeal. The Company is unable to predict what action the PRC may take regarding this issue (see "Overview - Restructuring the Electric Utility Industry"). Stock Repurchase On August 8, 2000, the Company's Board of Directors approved a plan to repurchase up to $35 million of the Company's common stock through the end of the first quarter of 2001. From August 8, 2000 through December 31, 2000, the Company repurchased an additional 417,900 shares of its outstanding common stock at a cost of $9.0 million. The Company made no repurchases of its stock during the nine months ended September 30, 2001. Dividends The Company's board of directors reviews the Company's dividend policy on a continuing basis. The declaration of common dividends is dependent upon a number of factors including the extent to which cash flows will support dividends, the availability of retained earnings, the financial circumstances and performance of the Company, the PRC's decisions on the Company's various regulatory cases currently pending, the effect of deregulating generation markets and market economic conditions generally. In addition, the ability to recover stranded costs in deregulation (as amended), conditions imposed on holding company formation, future growth plans and the related capital requirements and standard business considerations may also affect the Company's ability to pay dividends. Capital Structure The Company's capitalization percentage, including current maturities of long-term debt, at September 30, 2001 and December 31, 2000 is shown below: September 30, December 31, 2001 2000 --------------- -------------- Common Equity...................... 51.5 % 48.6 % Preferred Stock.................... 0.7 0.7 Long-term Debt..................... 47.8 50.7 ---------- ---------- Total Capitalization*........... 100.0 % 100.0 % ========== ========== * Total capitalization does not include as debt the present value of the Company's lease obligations for PVNGS Units 1 and 2 and EIP, which was $165 million as of September 30, 2001 and $166 million as of December 31, 2000. Including such obligations the Company's long-term debt percentage would increase to 51.8% for 2001 and 54.7% for 2000. 49 OTHER ISSUES FACING THE COMPANY RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT Stranded Costs The Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers ("stranded costs"). Stranded costs represent all costs associated with generation-related assets, currently in rates, in excess of the expected competitive market price over the life of those assets and include plant decommissioning costs, regulatory assets, and lease and lease-related costs. Utilities will be allowed to recover no less than 50% of stranded costs through a non-bypassable charge on all customer bills for five years after implementation of customer choice. The PRC could authorize a utility to recover up to 100% of its stranded costs if the PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is necessary to maintain the financial integrity of the public utility; (iii) is necessary to continue adequate and reliable service; and (iv) will not cause an increase in rates to residential or small business customers during the transition period. The Restructuring Act, as amended, also allows for the recovery of nuclear decommissioning costs by means of a separate wires charge over the life of the underlying generation assets (see "NRC Prefunding" below). The calculation of stranded costs is subject to a number of highly sensitive assumptions, including the date of open access, appropriate discount rates and projected market prices, among others. The Restructuring Act, as amended, requires the Company to file a transition plan which includes provisions for the recovery of stranded costs and other expenses associated with the transition to a competitive market no later than January 1, 2005. The Company is unable to predict the amount of stranded costs that it may file to recover at that time. The Company's previous proposal to recover its stranded costs under the original customer choice implementation dates would not accurately represent the Company's expected stranded costs under the amended implementation dates of the Restructuring Act. Approximately $151 million of costs associated with the power supply and energy services businesses under the Restructuring Act were established as regulatory assets. Because of the Company's belief that recovery is probable, these regulatory assets continue to be classified as regulatory assets, although the Company has discontinued Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) and adopted Statement of Financial Accounting Standards No. 101, "Regulated Enterprises--Accounting for the Discontinuance of Application of FASB Statement 71." The amendments to the Restructuring Act provide the opportunity for amortization of coal mine decommissioning costs currently estimated at approximately $100 million. The Company intends to seek recovery of these costs in its next rate case filing and believes that such costs are fully recoverable. The Company believes that any remaining portion of the regulatory assets will be fully recovered in future rates, including non-bypassable wires charge. The Company believes that the Restructuring Act, as amended, if properly applied provides an opportunity for recovery of a reasonable amount of stranded costs should such costs exist at the point of separation. If regulatory 50 orders do not provide for a reasonable recovery, the Company is prepared to vigorously pursue judicial remedies. The PRC will make a determination and quantification of stranded cost recovery prior to implementation of restructuring. The determination may have an impact on the recoverability of the related assets and may have a material effect on the future financial results and position of the Company. Transition Cost Recovery In addition, the Restructuring Act, as amended, authorizes utilities to recover in full any prudent and reasonable costs incurred in implementing full open access ("transition costs"). These transition costs are currently scheduled to be recovered from 2007 through 2012 by means of a separate wires charge. The PRC may extend this date by up to one year. The Company is unable to predict the amount of transition costs it may incur. To date, the Company has capitalized $22.4 million of expenditures that meet the Restructuring Act's definition of transition-related costs. Transition costs for which the Company will seek recovery include professional fees, financing costs, consents relating to the transfer of assets, management information system changes including billing system changes and public and customer education and communications. Recoverable transition costs are currently being capitalized and will be amortized over the recovery period to match related revenues. The Company intends to vigorously pursue remedies available to it should the PRC disallow recovery of reasonable transition costs. Costs not recoverable will be expensed when incurred unless these costs are otherwise permitted to be capitalized under current and future accounting rules. If the amount of non-recoverable transition costs is material, the resulting charge to earnings may have a material effect on the future financial results and position of the Company. NRC Prefunding Pursuant to NRC rules on financial assurance requirements for the decommissioning of nuclear power plants, the Company has a program for funding its share of decommissioning costs for PVNGS through a sinking fund mechanism (see "PVNGS Decommissioning Funding"). The NRC rules on financial assurance became effective on November 23, 1998. The amended rules provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers estimated decommissioning costs through cost of service rates or a "non-bypassable charge". Other mechanisms are prescribed, such as prepayment, surety methods, insurance and other guarantees, to the extent that the requirements for exclusive reliance on the fund mechanism are not met. The Restructuring Act, as amended, allows for the recoverability of 50% up to 100% of stranded costs including nuclear decommissioning costs (see "Stranded Costs"). The Restructuring Act, as amended, specifically identifies nuclear decommissioning costs as eligible for separate recovery over a longer period of time than other stranded costs if the PRC determines a separate recovery mechanism to be in the public interest. In addition, the Restructuring Act, as amended, states that it does not require the PRC to issue any order which would result in loss of eligibility to exclusively use external sinking fund methods for decommissioning obligations pursuant to Federal regulations. When final determination of stranded cost recovery is made and if the Company is unable to meet the requirements of the NRC rules permitting the use of an external sinking fund because it is unable to recover all of its estimated decommissioning costs through a non-bypassable charge, the Company may have to pre-fund or find a similarly capital intensive means to meet the NRC rules. There can be no assurance that such an event will not negatively affect the funding of the Company's growth plans. 51 MERCHANT PLANT FILING Senate Bill 266, enacted by the 2001 session of the New Mexico legislature, allowed public utilities to "invest in, construct, acquire or operate" a generating plant not intended to provide retail electric service, free of certain otherwise applicable limitations of the Public Utility Act. By order entered on March 27, 2001, the PRC found that these provisions of SB 266 raised issues such as cost allocations for ratemaking, revenue allocations for off-system sales, how the Commission can ensure the utility will meet its duty to provide service when the utility invests in such generating plant, how that plant will be financed and how transactions between regulated plant and such generating plant will be conducted. The PRC's March 27 order directed the Company to file a pleading addressing these issues by July 25, 2001. The Company filed such a pleading, to which the Commission's utility staff and intervenors filed responses. On October 2, 2001, the Commission entered another order, specifically directing the Company to file written testimony "providing detailed support for its positions and plans on each topic identified by the Commission's March 27 Order" and by responses filed by certain parties. The required testimony was to be filed by November 6, 2001. The Company subsequently requested and was granted an extension to December 10, 2001 in which to file the required testimony. The Company is unable to predict the impact these proceedings may have on its plans to expand its generating capacity (see "Overview - Competitive Strategy"). ACQUISITION OF WESTERN RESOURCES ELECTRIC OPERATIONS On November 9, 2000, the Company and Western Resources announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. Due to recent actions by the KCC, the Company believes that the transaction cannot be accomplished under the terms of the present acquisition agreement if the orders remain in effect (see below). Present Acquisition Agreement Under the present agreement and plan of restructuring and merger, the Company and Western Resources, whose utility operations consist of its Kansas Power and Light ("KPL") division and Kansas Gas and Electric ("KGE") subsidiary, will both become subsidiaries of a new holding company to be named at a future date. Prior to and as a condition to, the consummation of this combination, Western Resources will reorganize all of its non KPL and KGE assets, including its 85% stake in Protection One and its 45% investment in ONEOK, into Westar Industries which will be split off to Western Resources' shareholders prior to the acquisition of Western's electric utility assets by the Company. Under the present agreement, the new holding company will issue 55 million of its shares, subject to adjustment, to Western Resources' shareholders and Westar Industries and 39 million shares to the Company's shareholders. Before any adjustments, the new company will have approximately 94 million shares outstanding, of which approximately 41% will be owned by former Company shareholders and 59% will be owned by former Western Resources shareholders and Westar Industries. 52 In the present transaction, each Company share will be exchanged on a one-for-one basis for shares in the new holding company. The portion of each Western Resources share not converted into Westar Industries stock in connection with the split-off will be exchanged for a fraction of a share of the new holding company in accordance with an exchange ratio to be finalized at closing, depending on the impact of certain adjustments to the transaction consideration. Under the present agreement, Western Resources and Westar Industries have been given a limited incentive to reduce Western Resources net debt balance prior to the consummation of the transaction by selling non-utility assets or through certain other debt reduction acitivities. The present agreement contains a mechanism to adjust the transaction consideration based on certain activities not affecting the utility operations, which increase the equity of the utility. In addition, Westar Industries has the option of making equity infusions into Western Resources that will be used to reduce the utility's net debt balance prior to closing. Up to $641 million of additional equity infusions and existing intercompany receivables may be used to purchase additional new holding company common and convertible preferred stock. The effect of these activities would be to increase the number of new holding company shares to be issued to all Western Resources shareholders (including Westar Industries) in the present transaction. In February 2001, Westar Industries purchased 14.4 million Western Resources common shares at $24.358 per share (based on a 20-day look-back price at February 28, 2001) at an aggregate price of $350 million. As a result of this equity contribution, under the present agreement, the acquisition consideration may be adjusted to include an additional 4.3 million shares of the new holding company depending on the impact of future transactions between Western Resources and Westar Industries. Under the present agreement, the transaction will be accounted for as a reverse acquisition by the Company as the former Western Resources shareholders will receive the majority of the voting interests in the new holding company. For accounting purposes, Western Resources will be treated as the acquiring entity. Accordingly, all of the assets and liabilities of the Company will be recorded at fair value in the business combination as required by the purchase method of accounting. In addition, the operations of the Company will be reflected in the operations of the combined company only from the date of acquisition. Based on the volume weighted average closing price of the Company's common stock over the two days prior and two days subsequent to the announcement of the transaction of $24.149 per share, the indicated equity consideration of the present transaction is approximately $945 million, excluding the potential issuance of additional shares discussed above. There is approximately $2.9 billion of existing Western Resources debt giving the transaction an aggregate enterprise value of approximately $3.8 billion. There are plans for the new holding company to reduce and refinance a portion of the Western Resources debt. At closing, Jeffry E. Sterba, present chairman, president and chief executive officer of the Company, will become chairman, president and chief executive officer of the new holding company, and David C. Wittig, present chairman, president and chief executive officer of Western Resources, will become chairman, president and chief executive officer of Westar Industries. The 53 Board of Directors of the new company will consist of six current Company board members and three additional directors, two of whom will be selected by the Company from a pool of candidates nominated by Western Resources, and one of whom will be nominated by Westar Industries. The new holding company will be headquartered in New Mexico. Headquarters for the Kansas utilities will remain in Kansas. Under the present agreement, the Company expects that the shareholders of the new holding company will receive the Company's dividend. The Company's current annual dividend is $0.80 per share. There can be no assurance however that any funds, property or shares will be legally available to pay dividends at any given time or present if available, that the new holding company's Board of Directors will declare a dividend. Under the present agreement, the successful split-off of Westar Industries from Western Resources is required prior to the consummation of the transaction. The present transaction is also conditioned upon, among other things, approvals from both companies' shareholders and customary regulatory approvals from the KCC, the PRC, the Federal Energy Regulatory Commission, the Nuclear Regulatory Commission, the Federal Communications Commission and the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. In addition, an adverse regulatory outcome related to other actions involving rate making or approval of regulatory plans may affect the consummation of the transaction. The new holding company would be expected to register as a holding company with the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935. Recent Actions by the KCC On May 8, 2001, the KCC commenced an investigation of the proposed split-off of Westar Industries from Western Resources and whether the transaction will adversely affect the ability of Western Resources' electric utility operations to provide efficient and sufficient electric utility service at just and reasonable rates to its customers in the state of Kansas. The successful split-off of Westar Industries is a condition of the proposed acquisition of Western Resources' electric utility assets. On July 20, 2001, the KCC issued an order prohibiting Western from proceeding with the split-off of Westar Industries. The KCC ruled that the split-off, as presently designed, is inconsistent with the public interest. The KCC also ruled that the adverse impacts of the split-off on ratepayers could not be cured by a merger and directed Western Resources to file a financial plan within 90 days to restore Western Resources' financial ratings to the investment grade level of similarly situated electric public utilities. Western Resources filed for reconsideration of the order. On October 3, 2001, the KCC issued its order on reconsideration of the split-off order, reaffirming its prior order prohibiting the split-off as presently designed and confirming that a merger would not cure the problems associated with the split-off. In October 2001, Western Resources filed petitions for judicial review in the District Court of Shawnee County, Kansas, of the split-off order and the reconsideration order. On July 25, 2001, the KCC issued an order reducing the rates of Western Resources' electric utilities by the net amount of $22.7 million annually. Western Resources had sought a combined increase of approximately $151 million annually. Western Resources filed for reconsideration of the order and on September 5, 2001, the KCC slightly increased rates resulting in a revised net 54 reduction of approximately $15.7 million annually. Western Resources and other parties in the case filed for reconsideration of the KCC's revised rate order. On October 11, 2001, the KCC issued an order denying all petitions for reconsideration of the revised rate order. On July 30, 2001, the Company and Western Resources issued a joint release stating that the transaction as presently designed would be difficult to complete if the KCC orders remain in effect. The release announced that the Company and Western Resources would begin discussions on how to modify the transaction to make it possible to obtain necessary regulatory approvals. On August 13, 2001, the Company announced that Western Resources had decided to discontinue the talks about modifying the transaction and desired to attempt to pursue completion of the transaction as currently structured. The Company announced that it continues to believe that the transaction cannot be accomplished on its present terms due to the KCC orders. In addition, the Company announced that it believes that the rate case order will result in a material adverse effect on the financial condition of the combined companies and that there will be a failure of key conditions to consummation of the transaction if the KCC orders remain in effect. Western Resources has advised the Company that it does not believe that the rate case order results in a material adverse effect. Western Resources has requested that the Company file for regulatory approvals of the transaction as presently designed, despite the fact that the transaction requires the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as presently designed, the Company filed suit on October 12, 2001, in New York state court seeking declarations that the transaction could not be accomplished as presently designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as presently designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. Western Resources' response to the Complaint is due on November 26, 2001. The Company is unable to predict the outcome of this proceeding. On November 6, 2001, Western Resources filed its financial plan for restructuring its debt pursuant to the KCC's July 20 order. The plan is essentially comprised of two parts. The first part is stated by Western Resources as being designed to reduce debt by $100 to $175 million in the next several months by means of a rights offering of between 8.7 million and 19.1 million Westar Industries shares to Western Resources shareholders, representing between 10.2% and 19.9% of outstanding shares of Westar Industries. The second part is stated by Western Resources as being designed to reduce debt below $1.8 billion over the next one to three years through the sale by Western Resources of its Westar Industries common stock or Western Resources shares. The second part would not take place unless Westar Industries' stock price trades for 45 consecutive trading days at a price 25% higher than the price necessary to reduce Western Resources' debt below $1.8 billion. The first part of the plan is acknowledged by Western to be similar to the split-off ruled unlawful by the KCC but Western Resources asserts that it has made certain modifications in an attempt to address concerns raised by the KCC. The Company continues to monitor proceedings in Kansas but intends to pursue the litigation filed in New York. 55 WESTERN UNITED STATES WHOLESALE POWER MARKET A significant portion of the Company's earnings in 2001 was derived from the Company's wholesale power trading operations which benefited from strong demand and high wholesale prices in the Western United States. These market conditions were primarily driven by the electric power supply shortages in the Western United States. As a result of the supply imbalance, the wholesale power market in the Western United States became extremely volatile and, while providing many marketing opportunities, continues to present significant risk to companies selling power into this marketplace. Recently moderate weather in California as well as certain regulatory actions (see below) have caused a significant decline in the price of wholesale electricity in the Western United States wholesale power market. In addition, the Company expects conservation measures and new generation to put downward pressure on wholesale electricity prices. As a result of these trends, the Company expects its earnings from wholesale power trading operations to be significantly lower in the future (see "Results of Operations - Future Expectations"). The power market in the Western United States has been the subject of widespread national attention. At the heart of the situation were flaws in the California deregulation legislation and a significant imbalance between electric supply and demand. These circumstances were aggravated by other factors such as increases in gas supply costs, weather conditions and transmission constraints. The FERC and the California Public Utilities Commission ("CPUC") have entered a series of orders addressing, respectively, the wholesale pricing of electricity into the California market and the retail pricing of electricity to California consumers. These initiatives, individually or collectively, have recently put significant downward pressure on wholesale prices. The Company cannot predict the ultimate outcome of these governmental initiatives and their long-term effect on the Western United States power market or on the Company's ability to market into the California market. During 2001, regional wholesale electricity prices reached over $1,000 per MWh mainly due to the electric power shortages in the West although current price levels are much depressed from this level. Two of California's major utilities, SCE and PG&E, have been unable to fully recover their wholesale power costs from their ratepayers. As a result, both utilities experienced severe liquidity constraints that caused PG&E to seek bankruptcy protection while SCE has been forced to consider bankruptcy. In response to the turmoil in the California energy market, the FERC initially imposed a "soft" price cap of $150 per MWh for sales to the California Power Exchange ("Cal PX") and the California Independent System Operator ("Cal ISO") that required any wholesale sales of electricity into the these markets be capped at $150 MWh unless the seller could demonstrate that its costs exceed the cap. This price cap was effectively modified by FERC orders issued in March and April 2001 that directed certain power suppliers to provide refunds in excess of $100 million for overcharges calculated on the basis of a formula that sanctioned wholesale prices considerably in excess of the $150/MWh level. On April 26, 2001, the FERC adopted an order establishing prospective mitigation and a monitoring plan for the California wholesale markets and which established a further investigation of public utility rates in wholesale Western energy markets. The plan reflected in the April 26 order replaced the $150/MWh soft cap 56 previously established and applied during periods of system emergency. Thereafter, on June 19, 2001, the FERC issued still another order that changed the previous orders and expanded the price mitigation approach of the April 26 order to all of the western region. As a result of the price mitigation plan and other factors, such as moderate weather in California and lower gas prices, wholesale electric prices declined significantly at the end of the third quarter and remained low subsequent to the end of the third quarter. The Company is unable to predict the impact the price mitigation plan will ultimately have on the wholesale market, but expects that if wholesale electric prices remain at current levels, future operating revenues from Generation and Trading will be significantly lower than in the first half of 2001. The June 19 order also directed a FERC administrative law judge to convene a settlement conference to address potential refunds owed by sellers into the California market. The settlement conference, in which the Company participated, was ultimately unsuccessful, but the administrative law judge called in his recommendation to the FERC for an evidentiary hearing to resolve the dispute, suggesting that refunds were due; however, the estimated refunds were significantly lower than demanded by California, and in most instances, were offset by the amounts due suppliers from the Cal PX and Cal ISO. California had demanded refunds of approximately $9 billion from power suppliers. On July 25, 2001, acting on the recommendation of the administrative law judge, the FERC ordered an expedited fact-finding hearing to evaluate refunds for spot market transactions in California. The FERC also ordered a preliminary hearing to determine whether refunds are also due in 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 hearing on potential California refund obligations has not yet been completed. The Company is unable to predict the ultimate outcome of these FERC proceedings, or whether the Company will be directed to make any refunds as the result of a resulting FERC order. In 2001, approximately $2 million in wholesale power sales by the Company were made directly to the Cal PX, which was the main market for the purchase and sale of electricity in the state in the beginning of 2001, or the Cal ISO which manages the state's electricity transmission network. In January and February 2001, SCE and PG&E, major purchasers of power from the California PX and ISO, defaulted on payments due the Cal PX for power purchased from the PX in 2000. These defaults caused the Cal PX to seek bankruptcy protection. The Company has filed its proofs of claims in the Cal PX and PG&E bankruptcy proceeding. Total amounts due from the Cal PX or Cal ISO for power sold to them 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 these defaults of SCE and PG&E to other market participants, in proportion to their participation in the markets. The Company was invoiced for $2.3 million as its proportionate share under the Cal PX tariff. The Company, as well as a number of power marketers and generators, filed complaints with the FERC to halt the Cal PX's attempt to collect these payments under the charge-back mechanism, claiming the mechanism was not intended for these purposes, and even if it was so intended, such an application was unreasonable and destabilizing to the California power market. The FERC has issued a ruling on these complaints eliminating the "charge-back" mechanism. With the demise of the Cal PX in February 2001, the California Department of Water Resources ("Cal DWR") commenced a program of purchasing electric power needed to supply California utility customers serviced by PG&E and SCE as these utilities lacked the liquidity to purchase supplies. The purchases were financed by legislative appropriation, with the expectation that 57 this funding would be replaced with the issuance of revenue bonds by the state under recent legislation signed by the California governor. In the first quarter of 2001, the Company began to sell power to the Cal DWR. The Company has regularly monitored its credit risk with regard to its Cal DWR sales and believes its exposure is prudent. In addition to sales directly to California, the Company sells power to customers in other jurisdictions who sell to California and whose ability to pay the Company may be dependent on payment from California. The Company is unable to determine whether its non-California power sales ultimately are resold in the California market. The Company's credit risk is monitored by its Risk Management Committee, which is comprised of senior finance and operations managers. The Company seeks to minimize its exposure through established credit limits, a diversified customer base and the structuring of transactions to take advantage of off-setting positions with its customers. To the extent these customers who sell power into California are dependent on payment from California to make their payments to the Company, the Company may be exposed to credit risk which did not exist prior to the California situation. In 2001, in response to the increased credit risk and market price volatility described above, the Company provided an additional allowance against revenue of $2.1 million for anticipated losses to reflect management's estimate of the increased risk in the wholesale power market and its impact on 2001 revenues. This determination was based on a methodology that considers the credit ratings of its customers and the price volatility in the marketplace, among other things. Based on information available at September 30, 2001, the Company believes the total allowance for anticipated losses, currently established at $10.6 million, is adequate for management's estimate of potential uncollectible accounts. The Company will continue to monitor the wholesale power marketplace and adjust its estimates accordingly. The CPUC has commenced an investigation into the functioning of the California wholesale power market and its associated impact on retail rates. The Company, along with other power suppliers in California, has been served with a subpoena in connection with this investigation and has responded to the subpoena. The Company has been advised that the California Attorney General is conducting an investigation into possibly unlawful, unfair or anti-competitive behavior affecting electricity rates in California, and that Company documents will be subpoenaed in the future in connection with this investigation. Other related investigations have been commenced by other federal and state governmental bodies. In addition, there are several class action lawsuits that have been filed in California against generators and wholesale sellers of energy into the California market. These actions allege, in essence, that the defendants engaged in unlawful and unfair business practices to manipulate the wholesale energy market, fix prices and restrain supply, and thereby drive up prices. The Company is not a named defendant in any of these actions. The Company does not believe that these matters will have a material adverse effect on its results of operations or financial position. As noted above, SCE has publicly stated that it may be forced to declare bankruptcy. SCE is a 15.8% participant in PVNGS and a 48.0% participant in Four Corners. Pursuant to an agreement among the participants in PVNGS and an agreement among the participants in Four Corners Units 4 and 5, each participant 58 is required to fund its proportionate share of operation and maintenance, capital, and fuel costs of PVNGS and Four Corners Units 4 and 5. The Company estimates SCE's total monthly share of these costs to be approximately $7.1 million for PVNGS and $8.0 million for Four Corners. The agreements provide that if a participant fails to meet its payment obligations, each non-defaulting participant shall pay its proportionate share of the payments owed by the defaulting participant for a period of six months. During this time the defaulting participant is entitled to its share of the power generated by the respective station. After this grace period, the defaulting participant must make its payments in arrears before it is entitled to its continuing share of power. SCE has not defaulted on its payment obligations with respect to PVNGS and Four Corners. The Company is unable to predict whether the California situation will cause SCE to default on its payment obligations. Implementation of New Customer Billing System On November 30, 1998, the Company implemented a new customer billing system. Due to a significant number of problems associated with the implementation of the new billing system, the Company was unable to generate appropriate bills for all its customers through the first quarter of 1999 and was unable to analyze delinquent accounts until November 1999. As a result of the delay of normal collection activities, the Company incurred a significant increase in delinquent accounts, many of which occurred with customers that no longer have active accounts with the Company. As a result, the Company significantly increased its estimated bad debt costs throughout 1999 and 2000. The Company continued its analysis and collection efforts of its delinquent accounts resulting from the problems associated with the implementation of the new customer billing system throughout 2000 and identified additional bad debt exposure. By the end of 2000, the Company completed its analysis of its delinquent accounts and resumed its normal collection procedures. In addition, due to the significantly higher natural gas prices experienced in November and December 2000, the Company increased its bad debt expense by approximately $1 million for the nine months ended September 30, 2001 and $2 million for the year ended December 31, 2000 in anticipation of higher than normal delinquency rates. The Company expects this trend to continue as long as natural gas prices remain higher than historical levels. Based upon information available at September 30, 2001, the Company believes the allowance for doubtful accounts of $8.3 million is adequate for management's estimate of potential uncollectible accounts. The following is a summary of the allowance for doubtful accounts during the nine months ended September 30, 2001 and the year ended December 31, 2000:
September 30, December 31, 2001 2000 ------------- ------------ Allowance for doubtful accounts, beginning of year................................................... $ 8,963 $12,504 Bad debt expense............................................ 3,373 9,980 Less: Write off (adjustments) of uncollectible accounts.... 4,019 13,521 ------------- ------------- Allowance for doubtful accounts, end of period.............. $ 8,317 $ 8,963 ============= =============
59 Effects of Certain Events on Future Revenues The Company's 100 MW power sale contract with San Diego Gas and Electric Company ("SDG&E") expired on April 30, 2001 following FERC's acceptance for filing of a cancellation notice filed by the Company. The Company expects to replace these revenues, based on current market conditions. In addition, previously reported litigation between the Company and SDG&E regarding prior years' contract pricing has been resolved in the Company's favor. On October 1, 1999, Western Area Power Administration ("WAPA") filed a petition at the FERC requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA under the Company's Open Access Transmission Tariff on behalf of the United States Department of Energy ("DOE") as contracting agent for Kirtland Air Force Base ("KAFB"). On April 13, 2001, the FERC entered an order favorable to the Company, denying the WAPA transmission application. WAPA requested rehearing of FERC's April 13, 2001 order. In a proposed order issued on June 13, 2001, FERC granted WAPA's request for rehearing and ordered the Company to provide transmission service. If the parties do not agree upon the terms for that service, including compensation, FERC will establish those terms after a negotiation and briefing process. The parties have filed final briefs with the FERC and are engaged in settlement discussions before a settlement judge under FERC procedures. The June 13 order is a "proposed" order, and is not subject to requests for rehearing or judicial review. An order establishing terms and conditions (including compensation for transmission service) would be a "final" order that would be subject to requests for rehearing and to judicial review. The effect of the FERC's order to provide transmission service, instead of the current retail sale that the Company makes to DOE on behalf of KAFB, depends upon the final terms of any FERC order as well as the Company's ability to sell the power to a different customer and the price that the Company would obtain if it makes such a sale. The Company is evaluating its legal options in relation to the "proposed" order or any resulting "final" order. A related PRC proceeding has been stayed, pending the outcome of the FERC case (See Item 3. - "Legal Proceedings - Other Proceedings - KAFB Contract"). COAL FUEL SUPPLY In 1996, the Company was notified by SJCC that the Navajo Nation proposed to select certain properties within the San Juan and La Plata Mines (the "mining properties") pursuant to the Navajo-Hopi Land Settlement Act of 1974 (the "Act"). The mining properties are operated by SJCC under leases from the BLM and comprise a portion of the fuel supply for the SJGS. An administrative appeal by SJCC is pending. In the appeal, SJCC argued that transfer of the mining properties to the Navajo Nation may subject the mining operations to taxation and additional regulation by the Navajo Nation, both of which could increase the price of coal that might potentially be passed on to the SJGS through the existing coal sales agreement. The Company is monitoring the appeal and other developments on this issue and will continue to assess potential impacts to the SJGS and the Company's operations. The Company is unable to predict the ultimate outcome of this matter. 60 FUEL, WATER AND GAS NECESSARY FOR GENERATION OF ELECTRICITY The Company's generation mix for 2001 was 68.25% coal, 28.40% nuclear and 3.35% gas and oil. Due to locally available natural gas and oil supplies, the utilization of locally available coal deposits and the generally abundant supply of nuclear fuel, the Company believes that adequate sources of fuel are available for its generating stations. Water for Four Corners and SJGS is obtained from the San Juan River. BHP holds rights to San Juan River water and has committed a portion of those rights to Four Corners through the life of the project. The Company and Tucson have a contract with the USBR for consumption of 16,200 acre feet of water per year for the SJGS. The contract expires in 2005. In addition, the Company was granted the authority to consume 8,000 acre feet of water per year under a state permit that is held by BHP. The Company is of the opinion that sufficient water is under contract for the SJGS through 2005. The Company has signed a contract with the Jicarilla Apache Tribe for a twenty-two year term, beginning in 2006, for replacement of the current USBR contract for 16,200 acre feet of water. The contract has been approved by the USBR and also has received all requisite environmental approvals. The Company is actively involved in the San Juan River Recovery Implementation Program to mitigate any concerns with the taking of the negotiated water supply from a river that contains endangered species and critical habitat. The Company believes that it will continue to have adequate sources of water available for its generating stations. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with producers and marketers. These contracts are generally sufficient to meet the Company's peak-day demand. The Company serves certain cities which depend on EPNG or Transwestern Pipeline Company for transportation of gas supplies. Because these cities are not directly connected to the Company's transmission facilities, gas transported by these companies is the sole supply source for those cities. The Company believes that adequate sources of gas are available for its distribution systems. FERC MANDATED REGIONAL TRANSMISSION ORGANIZATIONS Beginning with the passage of the Public Utilities Regulatory Policy Act of 1978 and, subsequently, the Energy Policy Act, there has been a significant increase in the level of competition in the market for the generation and sale of electricity. The Energy Policy Act reduced barriers to market entry for companies wishing to build, own and operate electric generating facilities, and it also promoted competition by authorizing the FERC to require transmission service for wholesale power transactions. In this regard, in 1996, the FERC issued Order 888. Among other things, Order 888 required electric utilities controlling transmission facilities to file open access transmission tariffs that would make the utility transmission systems available to wholesale sellers and buyers of electric energy on a non-discriminatory basis. Order 888 encouraged utilities to investigate the formation of independent system operators, or ISOs, to operate transmission assets and provided criteria under which the formation, operation and governance of ISOs would be reviewed. On December 20, 1999, the FERC issued its Order 2000 on Regional Transmission Organizations, or RTOs. In this order, the FERC established timelines for transmission owning entities to join an RTO and defined the minimum characteristics and functions that an RTO must satisfy. 61 In January 1998, the Company entered into a development agreement with other transmission service providers and users to form an ISO in the southwest. As a result, Desert STAR, Inc. was incorporated as a non-profit organization in the State of Arizona on September 21, 1999. The Desert STAR Board of Directors and the FERC jurisdictional transmission owners (the"TO's") made various progress filings throughout 2000 and 2001 and held numerous stakeholder, advisory and Desert STAR Board of Director meetings to work through operational and technical documents to satisfy the FERC functions and characteristics for an approved RTO. The functions of Desert STAR RTO were envisioned to include the following: (1) tariff administration and design; (2) congestion management; (3) parallel flow internalization; (4) ancillary services; (5) total transmission capability and available transmission capability estimation; (6) market monitoring; (7) planning and expansion; and (8) inter-regional coordination. In an Order issued in March 2001, FERC granted provisional RTO status to a for-profit RTO with a Delaware LLC registry. The for-profit model's acceptance by FERC was of interest to the Desert STAR TO's because a for-profit company was viewed as having the proper motivation to efficiently facilitate competitive markets and was a stated ultimate goal of Desert STAR. As a result, the TO's informed the Desert STAR Board of Directors and stakeholders that they planned to investigate the feasibility of modifying the structure of Desert STAR to become a for-profit company. In July 2001, FERC issued a series of Orders requiring existing independent system operators and developing RTOs in the Eastern United States to enter into mediation to form a single RTO in the Northeast and a second in the Southeast. FERC expressed the desire that four RTO's be formed in the United States, two in the East, one in the Midwest and one in the West. On August 10, 2001 the Desert STAR Board approved the formation of WestConnect RTO LLC ("WestConnect"), a for-profit successor to DesertSTAR. On October 16, 2001 WestConnect filed its complete RTO package with FERC, requesting a Declaratory Order seeking confirmation from the FERC that the WestConnect filing satisfies FERC's Order 2000 requirements. NEW SOURCE REVIEW RULES The United States Environmental Protection Agency ("EPA") has proposed changes to its New Source Review ("NSR") rules that could result in many actions at power plants that have previously been considered routine repair and maintenance activities (and hence not subject to the application of NSR requirements) as now being subject to NSR. In November 1999, the Department of Justice at the request of the EPA filed complaints against seven companies alleging the companies over the past 25 years had made modifications to their plants in violation of the NSR requirements, and in some cases the New Source Performance Standards ("NSPS") regulations. Whether or not the EPA will prevail is unclear at this time. The EPA has reached a settlement with one of the companies sued by the Justice Department. Discovery continues in the pending 62 litigation. No complaint has been filed against the Company, and the Company believes that all of the routine maintenance, repair, and replacement work undertaken at its power plants was and continues to be in accordance with the requirements of NSR and NSPS. However, by letter dated October 23, 2000, the New Mexico Environment Department ("NMED") made an information request of the Company, advising the Company that the NMED was in the process of assisting the EPA in the EPA's nationwide effort "of verifying that changes made at the country's utilities have not inadvertently triggered a modification under the Clean Air Act's Prevention of Significant Determination ("PSD") policies." The Company has responded to the NMED information request. The nature and cost of the impacts of EPA's changed interpretation of the application of the NSR and NSPS, together with proposed changes to these regulations, may be significant to the power production industry. However, the Company cannot quantify these impacts with regard to its power plants. It is also not yet known what changes in EPA policy, if any, may occur in the NSR area as a result of the change in administration in Washington. The National Energy Policy released May 2001 by the National Energy Policy Development Group, called for a review of the pending NSR enforcement actions and that review continues by the EPA and the United States Attorney General. If the EPA should prevail with its current interpretation of the NSR and NSPS rules, the Company may be required to make significant capital expenditures which could have a material adverse effect on the Company's financial position and results of operations. COMPLIANCE WITH ENVIRONMENTAL LAWS AND REGULATIONS The normal course of operations of the Company necessarily involves activities and substances that expose the Company to potential liabilities under laws and regulations protecting the environment. Liabilities under these laws and regulations can be material and in some instances may be imposed without regard to fault, or may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Sources of potential environmental liabilities include the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980 and other similar statutes. The Company records its environmental liabilities when site assessments or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. The Company reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, the Company records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at undiscounted amounts). The Company's recorded estimated minimum liability to remediate its identified sites is $6.8 million. The ultimate cost to clean up the Company's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $11.6 million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company. 63 For the nine months ended September 30, 2001, the Company spent $1.2 million for remediation and $0.7 million for control and prevention. The majority of the September 30, 2001 environmental liability is expected to be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company. NATURAL GAS EXPLOSION On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The cause of the leak is unknown and the Company is conducting an investigation into the explosion. The Company also is cooperating with an investigation of the incident by the New Mexico Public Regulation Commission's Pipeline Safety Bureau. One lawsuit against the Company for personal injuries by a person working in the building at the time of the explosion has been filed and served on the Company. Several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur. There can be no assurance that the outcome of this matter will not have a material impact on the results of operations and financial position of the Company. NAVAJO NATION TAX ISSUES APS, the operating agent for Four Corners, has informed the Company that in March 1999, APS initiated discussions with the Navajo Nation regarding various tax issues in conjunction with the expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to the possessory interest tax and the business activity tax associated with the Four Corners operations on the reservation. The Company believes that the resolution of these tax issues will require an extended process and could potentially affect the cost of conducting business activities on the reservation. The Company is unable to predict the ultimate outcome of discussions with the Navajo Nation regarding these tax issues. LANDOWNER ENVIRONMENTAL CLAIMS Certain landowners owning property in the vicinity of the San Juan Generating Station have given notice to the Company of their intent to file suit against the Company and the other owners of the generating station. The asserted bases for the threatened litigation encompass a broad spectrum of allegations, including improper discharge of wastes and failure to remediate such discharges, poisoning of drinking waters, wrongful death and injury to persons, harm to landowner property, negligence, unnatural climate change, destruction of documents, racial discrimination, hostile work environment for employees at the plant and wrongful discharge of certain employees. The Company is in the process of reviewing these allegations and to date no suit has been filed. The Company has been informed that similar allegations have been made by the same landowners against Arizona Public Service Company, as operator of the Four Corners Power Plant, of which the Company is a co-owner. 64 NEW AND PROPOSED ACCOUNTING STANDARDS Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"): The Company implemented SFAS 133, as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at its fair value. SFAS 133, as amended, also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings. The results of hedge ineffectiveness and the change in fair value of a derivative that an entity has chosen to exclude from hedge effectiveness are required to be presented in current earnings. Because the Company's derivative instruments as defined by SFAS 133, as amended, are currently marked-to-market or are classified as cash flow hedges, the adoption of SFAS 133, as amended, did not have an impact on the net earnings of the Company. However, the adoption of SFAS 133, as amended, did increase comprehensive income by $6.1 million, net of taxes for the recording of the Company's cash flow hedges. The physical contracts will subsequently be recognized as a component of the cost of purchased power when the actual physical delivery occurs. At January 1, 2001, the derivative instruments designated as cash flow hedges had a gross asset position of $9.9 million on the hedged transactions. See Note 4 for financial instruments currently marked-to-market. It is a common practice within the electric utility industry to net offsetting purchase and sales contracts between two or more counterparties to facilitate transmission. This is commonly referred to as a "book-out." Whether a book-out occurs is dependent on a number of factors, including agreement by all parties in the chain of the transaction, efficiency of the transaction flow, congestion on the electrical transmission system, and system reliability issues. Book-outs do not occur until a short time before the electricity is due to be physically delivered, no matter when the original contracts in the chain were entered into, and have no legal standing should one of the parties in the chain default. The Derivatives Implementation Group ("DIG") of the FASB has reached a conclusion that all contracts for the sale or purchase of electricity that are subject to being booked out, whether that is the intent of the counterparties or not, may qualify for the normal sale or normal purchase exception if certain criteria are met. If the Company's contracts do not meet these criteria, it may be required to mark-to-market its transactions that it has classified as normal purchases and normal sales. The effective date for compliance with this implementation guide was June 30, 2001. A revision was made on October 10, 2001. The effective date of the revision to the implementation guidance for the Company is January 1, 2002. The Company is currently in the process of determining the impact of this guidance. 65 Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations ("SFAS 143"). In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS 143. The statement requires the recognition of a liability for legal obligations associated with the retirement of a tangible long-lived asset that result from the acquisition, construction or development and/or the normal operation of a long-lived asset. The asset retirement obligation is required to be recognized at its fair value when incurred. The cost of the asset retirement obligation is required to be capitalized by increasing the carrying amount of the related long-lived asset by the same amount as the liability. This cost must be expensed using a systematic and rational method over the related asset's useful life. SFAS 143 is effective for the Company beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and is unable to predict its impact on the Company's operating results and financial position at this time. Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS 144"). In August 2001, the FASB issued SFAS 144. The statement retains the requirements of the previously issued pronouncement on asset impairment, Statement of Financial Accounting Standards No. 121 ("SFAS 121"); however the SFAS 144 removes goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position. DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS Statements made in this filing that relate to future events are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that such forward-looking statements with respect to revenues, earnings, performance, strategies, prospects and other aspects of the business of the Company are based upon current expectations and are subject to risk and uncertainties, as are the forward-looking statements with respect to the Company's proposed acquisition of Western Resources and the businesses of the Company and Western Resources and the uncertainties associated with completing the transaction. 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, uncertainties relating to the Company's transaction with Western Resources and related costs, the performance of generating units and transmission system, and state and federal regulatory and legislative decisions and actions, including the wholesale electric power pricing mitigation plan ordered by FERC on June 18, 2001, rulings issued by the New Mexico Public Regulation Commission pursuant to the Electric Utility Industry Restructuring Act of 1999, as amended, and in other cases now pending or which may be brought before the FERC and the PRC and 66 any action by the New Mexico Legislature to further amend or repeal that Act, or other actions relating to restructuring or stranded cost recovery, or federal or state regulatory, legislative or legal action connected with the California wholesale power market, could cause the Company's results or outcomes to differ materially from those indicated by such forward-looking statements in this filing. In addition, factors that could cause actual results or outcomes related to the proposed acquisition of Western Resources to differ materially from those indicated by such forward looking statements include, risks and uncertainties relating to: litigation concerning or affecting the transaction, the possibility that shareholders of the Company or Western Resources will not approve the transaction, the risks that the businesses will not be integrated successfully, the risk that the benefits of the transaction may not be fully realized or may take longer to realize than expected, disruption from the transaction making it more difficult to maintain relationships with clients, employees, suppliers or other third parties, conditions in the financial markets relevant to the proposed transaction, the receipt of regulatory and other approvals of the transaction, that future circumstances could cause business decisions or accounting treatment to be decided differently than now intended, changes in laws or regulations, changing governmental policies and regulatory actions with respect to allowed revenue requirements, rates of return on equity and equity ratio limits, industry and rate structure, stranded cost recovery, operation of nuclear power facilities, acquisition, disposal, depreciation and amortization of assets and facilities, operation and construction of plant facilities, recovery of fuel and purchased power costs, decommissioning costs, present or prospective wholesale and retail competition (including retail wheeling and transmission costs), political and economic risks, changes in and compliance with environmental and safety laws and policies, weather conditions (including natural disasters such as tornadoes), population growth rates and demographic patterns, competition for retail and wholesale customers, availability, pricing and transportation of fuel and other energy commodities, market demand for energy from plants or facilities, changes in tax rates or policies or in rates of inflation or in accounting standards, unanticipated delays or changes in costs for capital projects, unanticipated changes in operating expenses and capital expenditures, capital market conditions, competition for new energy development opportunities and legal and administrative proceedings (whether civil, such as environmental, or criminal) and settlements, and the impact of Protection One's financial condition on Western Resources' consolidated results. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices and also adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. Information about market risk is set forth in Note 4 to the Notes to the Consolidated Financial Statements and incorporated by reference. The following additional information is provided. The Company uses value at risk ("VAR") to quantify the potential exposure to market movement on its open contracts and excess generating assets. The VAR is calculated utilizing the variance/co-variance methodology over a three day period within a 99% confidence level. The Company's VAR as of September 30, 2001 from its electric trading contracts was $10.8 million. 67 The Company's wholesale power marketing operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. The Company's VAR calculation considers this exposure. The Company's VAR is regularly monitored by the Company's Risk Management Committee which is comprised of senior finance and operations managers. The Risk Management Committee has put in place procedures to ensure that increases in VAR are reviewed and, if deemed necessary, acted upon to reduce exposures. In addition, the Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to access and monitor the financial conditions of counterparties. Credit exposure is also regularly monitored by the Company's Risk Management committee. The VAR represents an estimate of the potential gains or losses that could be recognized on the Company's wholesale power marketing portfolio given current volatility in the market, and is not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market rates, operating exposures, and the timing thereof, as well as changes to the Company's wholesale power marketing portfolio during the year. The Company's outstanding long-term debt is fixed rate debt and not subject to interest rate fluctuation. The Company has not historically utilized interest rate swaps or similar hedging arrangements to protect against fluctuations in interest rates, but may consider such financial instruments in the future depending on market conditions and the Company's financing requirements. PART II - OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS The following represents a discussion of legal proceedings that first became a reportable event in the current year or material developments for those legal proceedings previously reported in the Company's 2000 Annual Report on Form 10-K ("Form 10-K"). This discussion should be read in conjunction with Item 3. - Legal Proceedings in the Company's Form 10-K. PVNGS Water Supply Litigation As previously reported, The Company understands that a summons served on APS in 1986 required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons and the rights of the PVNGS participants, including the Company, to the use of groundwater and effluent at 68 PVNGS are potentially at issue in this action. APS, as the PVNGS project manager, filed claims that dispute the court's jurisdiction over the PVNGS participants' groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of such rights. In November 1999, the Arizona Supreme Court issued a decision confirming that certain groundwater rights may be available to the federal government and Indian tribes. APS and other parties have petitioned the United States Supreme Court for review of this decision and the petition was denied. In addition, the Arizona Supreme Court issued a decision affirming the lower court's criteria for solving groundwater claims. APS and other parties filed motions for reconsideration on one aspect of that decision. Those motions have been denied by the Arizona Supreme Court. APS and other parties petitioned the United States Supreme Court for review of the Arizona Supreme Court's decision affirming the lower court's criteria for resolving groundwater claims, and that petition was denied. The Company is unable to predict the outcome of this case. Purported Navajo Environmental Regulation As previously reported, in July 1995 the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the "Acts"). Pursuant to the Acts, the Navajo Nation Environmental Protection Agency is authorized to promulgate regulations covering air quality, drinking water and pesticide activities, including those that occur at Four Corners. In February 1998, the EPA issued regulations specifying provisions of the Clean Air Act for which it is appropriate to treat Indian tribes in the same manner as states. The EPA indicated that it believes that the Clean Air Act generally would supersede pre-existing binding agreements that may limit the scope of tribal authority over reservations. In February 1999, the EPA issued regulations under which Federal operating permits for stationary sources in Indian Country can be issued pursuant to Title V of the Clean Air Act. The regulations rely on authority contained in an earlier rule in which the EPA outlined treatment of tribes as states under the Clean Air Act. The Company as a participant in the Four Corners Power Plant ("Four Corners") and as operating agent and joint owner of San Juan Generating Station, and owners of other facilities located on other reservations located in New Mexico, has filed appeals to contest the EPA's authority under the regulations. On July 14, 2000, the DC Circuit issued its opinion denying the Company's motion for rehearing of the decision denying claims concerning the interpretation by EPA of tribal authority under the Clean Air Act. The Company filed a petition for writ of certiorari to the United States Supreme Court, which was denied on April 16, 2001. The Company does not expect any immediate impacts as a result of this decision but will continue to monitor developments with the Navajo Nation and EPA. On October 30, 2001, the DC Circuit issued its opinion granting the Company's appeal. The Court remanded the proceeding to the EPA for a new rulemaking on EPA's authority to issue federal operating permits in areas in which status as Indian Country may be in dispute. The United States has until December 14, 2001, to file a petition for rehearing in the appeal. The Company cannot predict the outcome of these proceedings or any subsequent determinations by the EPA. There can be no assurance that the outcome of these matters will not have a material impact on the results of operations and financial position of the Company. Royalty Claims Natural Gas Royalties Qui Tam Litigation As previously reported, the Company is defending a False Claims Act complaint (MDL Docket Number 1293) in the Federal District Court for the District of Wyoming, which alleged improper measurement of natural gas from federal and tribal lands and consequently, underpayment of royalties to the federal government. On May 18, 2001, the Wyoming court denied defendants' motion 69 to dismiss the complaint. A motion has been filed by the plaintiff asking the court to hold a conference to schedule further procedural steps, but no such conference has yet been set. The Company is vigorously defending this lawsuit and is unable to estimate the potential liability, if any, or to predict the ultimate outcome of this lawsuit. Quinque Operating Co. et al. v Gas Pipelines, et al As previously reported, a class action lawsuit against 233 defendants, including the Company, captioned Quinque Operating Co. et al. v. Gas Pipelines, et al., C.A. No. 99-CV-30 ("Quinque"), was filed in the state district court for Stevens County, Kansas by representatives of classes of gas producers, royalty owners, overriding royalty owners and working interest owners, alleging that the defendants, all engaged in various aspects of the natural gas industry, mismeasured natural gas and underpaid royalties for gas produced on non-federal and non-tribal lands. The claims for relief are based on state law, including a breach of contract claim. They are factually similar, however, to the allegations of "In re: Natural Gas Royalties Qui Tam Litigation", described in the Company's Form 10-K-Part I-Item 3. Legal Proceedings - "Royalty Claims". The Quinque complaint seeks actual damages, treble damages, costs and attorneys fees, among other relief. The Quinque case was removed to the United States District Court for the District of Kansas and transferred to the United States District Court for Wyoming ("Wyoming Court") to consolidate it with the In re: Natural Gas Royalties Qui Tam Litigation. Plaintiffs filed objections to the motions to consolidate and transfer and moved to remand the case to state court. On January 12, 2001, the Wyoming Court granted the plaintiff's motion to remand the case back to Kansas State Court. A motion to reconsider has been denied. This case has been remanded to the state court in Kansas, where, on June 8, 2001, a second amended petition was filed and served on the Company. The second amended petition is similar to the earlier petitions. A case management order has been entered that provides that the court will consider motions to dismiss on personal jurisdiction and other grounds and whether to allow the case to proceed as a class action before any discovery on the merits commences. The schedule, as recently revised, calls for the resolution of these preliminary issues by the spring of 2002. Discovery on jurisdictional and class certification issues only has commenced. The Company is vigorously defending this lawsuit and is unable to estimate the potential liability, if any, or to predict the ultimate outcome of this lawsuit. KAFB Contract The Company reported previously that the DOE had entered into an agency agreement with WAPA on behalf of KAFB, one of the Company's largest retail electric customers, by which WAPA would competitively procure power for KAFB. The proposed wholesale power procurement was to begin at the expiration of KAFB's power service contract with the Company in December 1999. On May 4, 1999, the Company received a request for network transmission service from WAPA pursuant to Section 211 of the Federal Power Act to facilitate the delivery of wholesale power to KAFB over the Company's transmission system. The Company denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB 70 is and will continue to be a retail customer until the date that KAFB can elect customer choice service under the provisions of the Restructuring Act of 1999. The Company also cited several provisions of Federal law that prohibit the provision of such service to WAPA. On October 1, 1999, WAPA filed a petition requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA on behalf of DOE and several other entities located on KAFB under the Company's Open Access Transmission Tariff. The petition claimed KAFB is a wholesale customer of the Company, not a retail customer. By order entered on April 13, 2001 the FERC denied the WAPA transmission application. The FERC order determined, among other things, that WAPA had failed to demonstrate that its sales to DOE are sales for resale and also that WAPA failed to qualify for certain claimed exemptions under the Federal Power Act that would have entitled it to provide expanded service to DOE. WAPA requested rehearing of FERC's April 13, 2001 order. In a proposed order issued on June 13, 2001, FERC granted WAPA's request for rehearing. FERC determined that WAPA qualified for an exemption to the prohibition against an order requiring service to retail customers and that FERC therefore could require the Company to provide the requested service. FERC directed the Company and WAPA to engage in negotiations concerning terms and conditions of service, including compensation. The parties have filed final briefs with the FERC and are engaged in settlement discussions before a settlement judge under FERC procedures. The June 13 order is a "proposed" order, and is not subject to requests for rehearing or judicial review. FERC may establish terms and conditions in a "final" order that would be subject to requests for rehearing and to judicial review. The Company is evaluating its legal options in relation to the "proposed" order or any resulting "final" order. In a separate but related proceeding, the Company and the United States Executive Agencies on behalf of KAFB are involved in a PRC case regarding a dispute over the specific Company tariff language under which the Company provides retail service to KAFB. The Company agreed to continue to provide service to KAFB after expiration of the contract, pending resolution of all relevant issues. The PRC case has been stayed, 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 ("Agreement"), agreeing that the City would offer employment to the water utility employees when the Agreement expired. The Agreement was assigned to Avistar, Inc., and it expired July, 2001. The City assumed all maintenance and operations, and offered employment to the employees. Because the employees would continue performing the same jobs at the same location(s), the Company had previously excluded the non-union employees from eligibility for severance benefits under the Company's non-union severance plans. Similarly, the IBEW Local 611 had been on notice that the Company had negotiated for the continued employment of the IBEW-represented employees, making them ineligible for severance benefits under Article 24 of the Collective Bargaining Agreement ("CBA") between the Company and the IBEW. In July 2001, the Agreement ended, and most of the water operations employees accepted employment with the City. However, on March 27, 2001, the IBEW began an internal Grievance claiming that about twenty-eight represented employees now employed by the City are nonetheless eligible for severance benefits under Article 24 of the CBA. The Company has denied their eligibility. The Company is evaluating its options, and the parties are pursuing informal settlement discussions pending the selection of an arbitrator. The Company is unable to predict the outcome of this matter. 71 WESTERN RESOURCES On November 9, 2000, the Company and Western Resources announced that both companies' boards of directors approved an agreement under which the Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. Due to recent actions by the KCC, the Company believes that the transaction cannot be accomplished under the terms of the present acquisition agreement if the orders remain in effect (see "Item 2. - Management's Discussion and Analysis and Results of Operations - Other Issues Facing The Company - Acquisition of Western Resources Electric Operations.") Western Resources has demanded that the Company file for regulatory approvals of the transaction as presently designed, despite the fact that the transaction requires the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as presently designed, the Company filed suit on October 12, 2001, in New York state court seeking declarations that the transaction could not be accomplished as presently designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as presently designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. Western Resources' response to the Complaint is due on November 26, 2001. The Company is unable to predict the outcome of this proceeding. REEVES GENERATING STATION ENVIRONMENTAL MATTERS On August 15, 2001, the City of Albuquerque Air Quality Division of the Environmental Health Department ("City"), issued a Notice of Violation ("NOV") to the Company, alleging that in the period of March 10, 1998 through June 30, 2001, the Company had exceeded the pound-per-inch NOx limitations in the operating permit for the Reeves Generating Station. The Company was assessed a proposed penalty in the amount of $1.8 million. The Company disagreed with the alleged violations and entered into discussions with the City to attempt to achieve a resolution of the matter. The parties are presently in the process of negotiating a settlement agreement that would resolve the matter without the admission of liability by the Company. 72 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K a. Exhibits: 10.5 Water Supply Agreement between the Jicarilla Apache Tribe and Public Service Company of New Mexico, dated July 17, 2000. 10.9.8 Amendment 11 to the Coal Sales Agreement, dated August 31, 2001 among San Juan Coal Company, the Company and Tucson Electric Power Company. (Confidential treatment was requested to portions of this exhibit, and such portions were omitted from this exhibits filed and were filed separately with the Securities and Exchange Commission.) 10.83 Transportation Agreement Buy Out Agreement, dated August 31, 2001 among San Juan Transportation Company, the Company and Tucson Electric Power Company. (Confidential treatment was requested to portions of this exhibit, and such portions were omitted from this exhibits filed and were filed separately with the Securities and Exchange Commission.) 10.84 Coal Sales Agreement Buy Out Agreement, dated August 31, 2001 among San Juan Coal Company, the Company and Tucson Electric Power Company. (Confidential treatment was requested to portions of this exhibit, and such portions were omitted from this exhibits filed and were filed separately with the Securities and Exchange Commission.) 10.85 Underground Coal Sales Agreement, dated August 31, 2001 among San Juan Coal Company, the Company and Tucson Electric Power Company. (Confidential treatment was requested to portions of this exhibit, and such portions were omitted from this exhibits filed and were filed separately with the Securities and Exchange Commission.) 15.0 Letter Re: Unaudited Interim Financial Information b. Reports on Form 8-K: Report dated and filed August 16, 2001 reporting Regulators decline to reconsider the Company's Holding Company Order. Report dated and filed August 17, 2001 reporting the Company names Energy Risk Management Strategist, R. Martin Chavez to Board of Directors. Report dated and filed September 13, 2001 reporting the Company declares Common and Preferred Stock Dividend. Report dated and filed September 18, 2001 reporting the Company's Comparative Operating Statistics for the month of August 2001 and 2000 and the year ended August 31, 2001 and 2000. Report dated and filed September 19, 2001 reporting the Company's Board of Directors approves activation of New Holding Company, PNM Resources, Inc. 73 Report dated and filed October 11, 2001 reporting the Company's Comparative Operating Statistics for the month of September 2001 and 2000 and the year ended September 30, 2001 and 2000. Report dated and filed October 16, 2001 reporting the Company asked court to rule on Western Resources Agreement and related complaint of PNM, HVOLT Enterprises, Inc., HVK, Inc., and HVNM, Inc. Plaintiffs, vs. Western Resources, Inc., Defendant. Report dated and filed October 23, 2001 reporting the Company its Third Quarter 2001 Earnings Conference Call. Report dated and filed October 25, 2001 reporting the Company Reports Quarter and Nine Months Ended September 30, 2001 Earnings Announcement and Consolidated Statement of Earnings. Report dated and filed November 2, 2001 reporting the Company Merchant Utility Model combines growth with Stability, Chief Executive Jeff Sterba Tells Analysts. 74 Signature - --------- Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW MEXICO ----------------------------------------------- (Registrant) Date: November 14, 2001 /s/ John R. Loyack ----------------------------------------------- John R. Loyack Vice President, Corporate Controller and Chief Accounting Officer (Officer duly authorized to sign this report) 75 EX-10 3 exh105.txt EXHIBIT 10.5 Exhibit 10.5 WATER SUPPLY AGREEMENT BETWEEN THE JICARILLA APACHE TRIBE AND PUBLIC SERVICE COMPANY OF NEW MEXICO THIS AGREEMENT (the "Agreement") made this 17th day of July, 2000, is between the JICARILLA APACHE TRIBE (the "Tribe") and PUBLIC SERVICE COMPANY OF NEW MEXICO ("PNM") in its individual capacity and in its capacity as operating agent of the San Juan Generating Station ("SJGS"). The Tribe and PNM are collectively referred to as "Parties" and individually as "Party." EXPLANATORY RECITALS PNM, as operating agent of the SJGS, is in need of a future water supply for electric power generation, and uses related and incidental thereto, and The Tribe is the owner of certain water rights pursuant to the Jicarilla Apache Tribal Water Rights Settlement Act of October 23, 1992, 106 Stat. 2237 (the "Settlement Act"), and the Act of June 13, 1962, 76 Stat. 96 (the " NIIP/ San Juan-Chama Act"), and The Tribe has the right to deplete up to 25,500 acre feet per year from the Navajo Reservoir Supply pursuant to the Settlement Act and the Contract between the Tribe and the United States of America dated December 8, 1992 (the "Federal Contract"), and The Tribe has the right to market such water pursuant to the Settlement Act and the Federal Contract, and The Tribe desires to subcontract under the Federal Contract to market water to PNM and PNM desires to purchase such water supply under the terms and conditions of this Agreement. ACCORDINGLY, in consideration of the mutual covenants in this Agreement, the Parties agree as follows: 1 ARTICLE 1 GENERAL DEFINITIONS 1.1 "Tribe" means the Jicarilla Apache Tribe. The Tribe is a federally recognized Indian tribe organized under the Indian Reorganization Act. 1.2 "Navajo Reservoir" or "Project" means the reservoir created by the impoundment of the San Juan River at the Navajo Dam as authorized by the Act of Congress of April 11, 1956, 70 Stat. 105, as amended. 1.3 "Navajo Reservoir Supply" means the water supply in the Navajo Reservoir as it is defined in the Federal Contract and delivered by the United States Bureau of Reclamation ("USBR"). 1.4 "Notice" is proper notice provided pursuant to Article 10 of this Agreement. 1.5 "NEPA" means the National Environmental Policy Act. 42 U.S.C.ss.ss. 4321 et seq. 1.6 "ESA" means the Endangered Species Act. 16 U.S.C.ss.ss.1531 et seq. 1.7 "PNM" means Public Service Company of New Mexico acting in its individual capacity and in its capacity as operating agent for San Juan Generating Station ("SJGS") and PNM's successors and assigns. 1.8 "SJGS weir" means the diversion structure located in the San Juan River at Mile Marker 166.1, based on the San Juan River Recovery Implementation Program Geomorphic Survey. 1.9 "USBR" means the United States Bureau of Reclamation. 1.10 "USBR CRSP Rate" means the calculated delivery rate ($/AF), based on a maximum of 16,200 acre-feet of water per annum, set by the USBR for Colorado River Storage Project ("CRSP") long term municipal and industrial contracts. The Parties understand that the USBR CRSP Rate is reviewed and adjusted annually in accordance with the USBR Debt Service Methodology used for pricing water from the CRSP as follows: 1.10.1 That part of the Federal debt ("estimated debt") incurred in developing water for consumptive uses in the CRSP initial units served by this Agreement will be established by USBR as of January 1, 2006. 2 1.10.2 The first annual payment will be calculated from an amortization of the estimated debt, using the annuity due formula, and based on a 40-year payment term at an interest rate that is the annual average rate for 10-year Treasury constant maturities for the year previous to the year of contract execution. 1.10.3 For each succeeding year thereafter, the estimated debt to be serviced shall be recalculated in accordance with the following: Dn = Dn-1 - Pn-1 + In-1 +/- (DELTA) Cn-1 Where: Dn = The recalculated total debt for water to be serviced by this Agreement; Dn-1 = The debt to be serviced by this Agreement as it existed at the beginning of the previous year; Pn-1 = Payments for water service made by PNM for the previous year; I n-1 = Interest accrued for the previous year based on the annual average interest rate of that year for 10-year Treasury constant maturities; +/-(DELTA)Cn-1 = A pro rata share of any change during the previous year in multipurpose costs allocated to consumptive use for the consolidated CRSP. 1.10.4 The calculated delivery rate per acre-foot for payments after the first year shall then be determined in accordance with the following procedure: a. Divide Dn by 16,200 acre-feet; b. Amortize the amount determined in step a., using the annuity due formula, with the interest rate determined as described above and for the number of years equal to 40 minus the number of years the contract has been in effect. 3 ARTICLE 2 TERM OF AGREEMENT 2.1 The term of this Agreement shall be from the date as of which it has been executed by both Parties to December 31, 2027, unless earlier terminated pursuant to the provisions of Article 14. 2.2 The Parties shall enter into good faith discussions no later than January of 2022 regarding the potential extension or renewal of this Agreement upon mutually agreeable terms. ARTICLE 3 WATER AVAILABILITY 3.1 Beginning on January 1, 2006, and continuing through December 31, 2027, the Tribe shall supply and deliver, through its agent USBR pursuant to the Federal Contract, to the SJGS weir, sufficient water from the Navajo Reservoir Supply to allow PNM to divert and consume up to 16,200 acre-feet of water between January 1 and December 31 of each year. Provided, however, that in no calendar year will the Tribe, through its agent USBR, under this Agreement, release more than 16,200 acre-feet of water from Navajo Reservoir for all uses pursuant to this Agreement. Delivery of water to the SJGS weir shall be at such times as scheduled by PNM in coordination with the USBR, and PNM shall pay the Tribe for the water as provided in Article 5. 3.2 PNM shall have no holdover storage rights in Navajo Reservoir from year to year, and PNM hereby relinquishes claim to any annual water supply to which it is entitled hereunder, but has not utilized by December 31 of each year. Any water subject to delivery hereunder not called for by the end of each calendar year shall become integrated with the water supply for all purposes of the Navajo Reservoir at that time. 3.3 PNM may, in its sole discretion, determine the timing and manner in which water is diverted at the SJGS weir subject to an appropriate permit from the New Mexico State Engineer ("State Engineer") and compliance with any applicable laws and regulations. 4 ARTICLE 4 WATER USE 4.1 The water used by PNM under this Agreement shall be for the purposes of coal mining, irrigation of reclaimed surface mined lands, electric power generation and uses incidental to all of the foregoing, and other beneficial industrial purposes at the SJGS, unless subcontracted by PNM in accordance with Article 4.2. 4.2 Subject to required approvals of the Tribe and Secretary of the Interior or designee, PNM may dispose of water acquired under this Agreement to third parties in the event that the water is not needed at or in connection with the SJGS, provided, that if PNM receives a price for disposal of water to third parties in excess of the USBR CRSP rate then current, the Parties shall share equally the amount received in excess of the USBR CRSP rate, after deduction of PNM's reasonable direct administrative costs. PNM shall provide an accounting of such direct administrative costs to the Tribe. 4.3 Nothing in this Agreement shall affect PNM's right to determine the source or order in which PNM utilizes its permitted rights that constitute the water supply for SJGS and uses related and incidental thereto, including water purchased pursuant to this Agreement. ARTICLE 5 PAYMENT FOR WATER 5.1 Beginning on the execution date of this Agreement, and on January 15 of each year thereafter for five (5) years, PNM shall make prepayments to the Tribe totaling $2,033,073.00 as follows: Year: 2000 2001 2002 2003 2004 2005 ---- ---- ---- ---- ---- ---- Amount: $65,583 $131,166 $262,332 $393,498 $524,664 $655,830 5.2 Subject to the Tribe's ability to supply and deliver, through its agent USBR pursuant to the Federal Contract, water during the 2006 to 2027 term of this Agreement, and except as otherwise provided herein, PNM shall pay to the Tribe during each year of the Agreement the Annual Contract Rate times 16,200 acre-feet, less $92,412.00, to secure PNM's right to use up to 16,200 acre-feet each year. 5 5.2.1 The Annual Contract Rate will be established as follows: On January 1, 2006, the Annual Contract Rate will be the USBR CRSP Rate as of January 1, 2006. Each successive year after establishment of the initial Annual Contract Rate in 2006, the Annual Contract Rate will be adjusted to the USBR CRSP Rate as of January 1 of each subsequent year; provided, however, that any change in the Annual Contract Rate for each year (whether an increase or a decrease) will be limited to no more than ten percent (10%) of the previous year's Annual Contract Rate. 5.2.2 To demonstrate the application of this rate adjustment, hypothetical examples of contract payments have been calculated based on the Annual Contract Rate methodology set out in Section 5.2.1 and are attached, for illustration purposes only, as Exhibit "A." 5.2.3 The Tribe will provide Notice to PNM of the Annual Contract Rate. The Tribe shall provide such Notice to PNM no later than January 10 of each year. After Notice from the Tribe, the annual contract payment by PNM shall be made no later than February 10 of each year and shall be made by wire transfer to a financial institution designated by Notice from the Tribe to PNM. 5.3 PNM will pay to the Tribe, within thirty (30) days of receipt of the Tribe's invoice, the Tribe's share of the Navajo Dam and Reservoir capital construction costs, provided by the Federal Contract to be $2.60 per acre-foot per annum, which is a fixed payment of $42,120 annually during the period 2006 through 2012. 5.4 PNM will also pay the Tribe, within thirty (30) days of receipt of the Tribe's invoice, PNM's proportionate share of the annual costs of the operation and maintenance ("O&M") of Navajo Dam and Reservoir and associated facilities that are assigned to the Tribe by USBR through Section 10(a) (iii) of the Federal Contract. The Parties acknowledge that payment of O&M costs will be determined by USBR in accordance with the USBR's payment schedules and criteria. The Tribe and PNM will work jointly with USBR to establish PNM's actual proportionate share and the 6 terms and conditions of this O&M payment procedure. At its own expense, PNM may take appropriate action, by and through the Tribe, to protest, if necessary, any change by USBR during the term of this Agreement to the O & M rate or the annual O & M charges attributable to the water delivered under this Agreement. The Tribe agrees to cooperate fully in any such protest. 5.5 The payments described in this Article 5 represent the total consideration due for the water purchased under this Agreement. Neither PNM, SJGS nor its owners, affiliates and/or their successors or assigns shall be subject to any regulation, fees, licenses or taxation directly or indirectly by the Tribe as a result of the use of the water supply or as a result of this Agreement, except as set forth herein. Each Party shall bear its own administrative costs. ARTICLE 6 MEASUREMENT AND RESPONSIBILITY FOR DISTRIBUTION 6.1 The water furnished under this Agreement will be supplied and delivered by the Tribe, through its agent USBR pursuant to the Federal Contract at the SJGS weir and PNM agrees to make arrangements for the transportation of such water to place of use at PNM's own expense. 6.2 PNM will measure the quantity of water diverted from the San Juan River under this Agreement with a recording or totalizing flow meter such as a NewSonics Model CM800 or equivalent. Beginning in 2007 and for the duration of this Agreement, records of the previous year's diversion by PNM at the SJGS weir will be provided by PNM to the Tribe and USBR no later than January 30 of each year. 6.3 The Tribe shall not be responsible for the diversions, control, carriage, handling, use disposal, or distribution of water taken by PNM hereunder, and PNM shall hold the Tribe harmless on account of damage or claim of damage of any nature arising out of or connected with the diversion, control, carriage, handling, use, disposal, or distribution of such water. ARTICLE 7 WATER SHORTAGES AND LIMITATIONS 7.1 The delivery of water during any calendar year is conditioned upon and subject to the following: 7 7.1.1 Any shortages to the Navajo Reservoir Supply that are determined to exist by the Secretary of the Interior (the "Secretary") for any reason will be shared among Project beneficiaries only pursuant to all Project authorizations, the Federal Contract and any other applicable laws. In no event shall any liability accrue against the United States, the Tribe or any officers, agents, or employees of either for any damage, direct or indirect, arising from a shortage for any causes. 7.1.2 If shortages are declared by the Secretary such that the Tribe cannot supply and deliver through its agent USBR pursuant to the Federal Contract in accordance with Article 3.1 of this Agreement all the water contracted for from the Navajo Reservoir Supply, PNM's payment will be reduced in proportion to the amount of water not supplied, or credited against the following year's payment. Provided, that shortage calculations will be based on the then current, daily demand at the SJGS weir for only the period of the declared shortages. The Tribe and PNM will work with USBR to obtain an accounting of the accumulated shortages based on PNM diversion and demand records. 7.2 This Agreement and all water delivered pursuant hereto shall be subject to and controlled by the Colorado River Compact, the Boulder Canyon Project Act, the Boulder Canyon Project Adjustment Act, the Upper Colorado River Basin Compact, the Mexican Water Treaty of February 3, 1944, the Colorado River Storage Project Act, the NIIP/ San Juan-Chama Act, the Colorado River Basin Project Act and other applicable federal law. In the event deliveries to PNM are required to be curtailed under and by reason of any of the provisions of the foregoing, PNM agrees to a reduction of the amount of water delivered hereunder as the Secretary determines necessary to comply with said acts. In that event, PNM's Annual Contract Rate payment to the Tribe will be reduced in proportion to the amount of water not supplied, or credited against the following year's payment. Provided, that such calculations will be based on the then current, daily demand at the SJGS weir for only the period of the curtailment. 8 ARTICLE 8 PAYMENT CONDITIONED UPON DELIVERY 8.1 PNM's obligation to pay the Tribe is conditioned upon the delivery of the water at the SJGS weir, all as provided for in this Agreement. 8.2 Subject to the Tribe's ability to supply and deliver, through its agent USBR pursuant to the Federal Contract, the water contracted for from Navajo Reservoir Supply at the SJGS weir or otherwise as provided in this Agreement, PNM shall take all the water contracted for, or shall pay for the water as if taken. ARTICLE 9 OTHER PROVISIONS 9.0 This Agreement incorporates by reference the Federal Contract, a true and correct copy of which is attached as Exhibit "B." 9.1 This Agreement is subject to the requirements of NEPA and ESA. The Parties understand that USBR will conduct an Indian Trust Assets Review in compliance with NEPA, and that such review will address any potential concerns of the Navajo Nation and/or the Colorado Ute Tribes. 9.2 This Agreement is subject to the approval of the Secretary or his designee pursuant to the Federal Contract. 9.3 Notwithstanding the provisions of Article 14, if a Party is in default, which default continues for more than thirty (30) days after Notice, the Parties may seek to remedy the default under the Dispute Resolution provisions of this Agreement (Article 15). 9.4 The Parties agree that for the duration of this Agreement or any extensions thereof, the Tribe will replace the USBR as the supplier of the water to PNM from the Navajo Reservoir Supply for the purpose of providing an otherwise historic/existing depletion for the SJGS at its weir. 9.5 The provision of Section 9.4 shall in no way diminish future positions that either Party may take regarding the disposition or characterization of this water supply, or depletion thereof, upon termination of this Agreement. 9 9.6 Both Parties hereby request the USBR, as the "action agency" for purposes of complying with Section 7 of the ESA, to state in its consultation document that the depletion will continue to occur by SJGS at its weir, but that the Tribe will be acting as the supplier of the water for that depletion. 9.7 This Agreement is contingent upon the issuance of a diversion permit for the contracted water from the State Engineer that is final and not appealable. All payments made pursuant to Article 5 are not subject to refund if the diversion permit is not issued, but all payment obligations will cease and this Agreement will terminate as of the date and in the event of a final denial of a diversion permit by the State Engineer. 9.8 The Tribe shall obtain all requisite approvals under the Federal Contract. 9.9 The Tribe shall comply with all requirements of the Federal Contract related to this Agreement. 9.10 The Parties shall cooperate in all required approval processes. 9.11 The Tribe represents, through a resolution, a copy of which is attached as Exhibit "C," that it has obtained all requisite tribal approvals and has delegated the requisite authority to the signatory hereof to bind the Tribe. 9.12 PNM represents, through the signature of its authorized representative, that PNM has authority to enter into this Agreement and that this Agreement is a binding obligation of PNM individually and as operating agent of SJGS. 9.13 Both Parties are relying on the advice of their own technical and legal experts in entering into this Agreement and there are no warranties or representations by either Party other than those expressly contained herein. Any ambiguities herein shall not be construed in favor of or against either Party as the drafter hereof. ARTICLE 10 NOTICES 10.1 Any Notice, demand, or request authorized by this Agreement shall be deemed to have been given if mailed (return receipt requested), hand delivered, or faxed as follows: 10 To PNM: Corporate Secretary Public Service Company of New Mexico Alvarado Square Albuquerque, NM 87158 With a copy to: Plant Manager San Juan Generating Station P.O. Box 227 Waterflow, NM 87421 To Tribe: President Jicarilla Apache Tribe P.O. Box 507 Dulce, NM 87528 With a copy to: Lester K. Taylor, Esq. Nordhaus, Haltom, Taylor, Taradash & Frye 500 Marquette Ave. NW, Suite 1050 Albuquerque, NM 87102 To USBR: Regional Director Upper Colorado Region Attn: UC-400 125 South State Street Room 6107 Salt Lake City, Utah 84138-1102 All Notices and demands given or required to be given by a Party to the other Party shall be deemed to have been properly given if and when delivered in person, sent by facsimile (with verification of receipt) or three (3) business days after having been deposited with the U.S. Postal Service and sent by registered or certified mail, postage prepaid. 11 In the event either Party delivers a Notice by facsimile, as set forth above, such Party agrees to deposit the originals of the Notice in a Post Office, or mail depository maintained by the U.S. Postal Service, postage prepaid, and addressed as set forth above. Such deposit in the U.S. Mail shall not affect the deemed delivery of the Notice by facsimile, provided that the procedures set above are fully complied with. 10.2 The designation of the addressee or the address may be changed by Notice given in the same manner as provided above in Section 10.1. ARTICLE 11 ASSIGNMENT 11.1 The provisions of this Agreement shall apply to and bind the successors and assigns of the Parties, but no assignment of this Agreement or of any right or interest hereunder shall be valid until approved in writing by the other Party and the Secretary or designee, which consent shall not be unreasonably withheld. 11.2 Notwithstanding the foregoing, PNM may, without the requirement of prior consent, assign this Agreement to any entity, as a result of a reorganization of the assets, business functions, or structure of PNM, which is within the resulting group of entities under common ownership with PNM. Any change of name by PNM shall not be considered an assignment. ARTICLE 12 WATER AND AIR POLLUTION CONTROL AND WATER CONSERVATION 12.1 PNM shall comply with all applicable water and air pollution control laws now or hereafter in force, and shall be responsible for obtaining all required licenses and permits. 12.2 Prior to accepting delivery of water under this Agreement, PNM shall develop an effective water conservation program, which shall contain definite water conservation objectives, appropriate economically feasible water conservation measures, and time schedules for meeting those objectives. At subsequent three-year intervals, PNM shall submit a report on the results of the program to USBR and the Tribe for review. Based on the conclusions of the review, the Tribe, in cooperation with USBR, and PNM shall consult and agree to continue or to revise the existing water conservation program. 12 ARTICLE 13 EQUAL OPPORTUNITY AND RELATED LAWS 13.1 PNM is an Equal Opportunity employer. Executive Orders 11246, 11625, 11701, and 11758, as amended or superseded, and all regulations issued thereunder, as well as all applicable laws, rules and regulations relating to Equal Employment Opportunity and affirmative action are incorporated in this Agreement by reference. 13.2 The Tribe is exempt from the provisions of Title VII of the Civil Rights Act of 1964 and from federal affirmative action programs including Executive Order No. 11246. ARTICLE 14 FORCE MAJEURE AND ECONOMIC IMPRACTICABILITY 14.1 Neither Party shall be considered to be in default in respect to any obligation hereunder, if delays in or failure of performance shall be due to Uncontrollable Forces. "Uncontrollable Forces" shall mean any cause beyond the control of the Party affected and not due to its fault or negligence, including, but not limited to, acts of God, flood, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance, sabotage, strikes or other labor disturbances, or restraint by court or public authority, any of which such Party could not reasonably have been expected to avoid, and which by the exercise of due diligence it is unable to overcome. Neither Party shall, however, be relieved of liability for failure of performance if such failure is due to removable or remediable causes which it fails to remove or remedy with reasonable dispatch. Nothing contained herein, however, shall be construed to require either Party to prevent or settle a strike or other labor disturbance against its will. The Party whose performance hereunder is so affected shall immediately notify the other Party of all pertinent facts and take all reasonable steps to promptly and diligently prevent such causes if feasible to do so, or to minimize or eliminate the effect thereof without delay. 14.2 If, in PNM's sole business judgment, it becomes necessary, for any Business Reason, to deactivate, decommission or cease operation of all or a portion of SJGS, PNM may elect to be excused from performance of 13 all or a pro-rata portion (based on the proportional decrease in need for water at SJGS) of its obligations under this Agreement to take and pay for water; provided, however, that this election may be exercised by PNM only upon satisfaction of the following conditions: 14.2.1 PNM must notify the Tribe in writing no later than thirty (30) days after the decision has been made to deactivate, decommission or cease operation of all or a portion of SJGS; and 14.2.2 PNM shall pay to the Tribe, within sixty (60) days of such notification, as liquidated damages and not as a penalty, a sum of money no greater than the total of all payments made hereunder by PNM to the Tribe during the previous twelve (12) months of the term of this Agreement or a pro-rata sum if the reduced water quantity taken pursuant to this Article is less than the full amount to be supplied under this Agreement. The Parties agree that such sum is reasonable in light of any damages the Tribe may suffer as the result of such a termination for convenience and that any actual damages would be difficult of ascertainment. For purposes of this Article 14.2, the term "Business Reason" includes but is not limited to any one or more of the following: effects of judicial or regulatory orders or decrees; inability to obtain permits, licenses, or authorizations from governmental bodies having jurisdiction; lack of availability of materials, supplies, equipment or services required to operate SJGS or a portion thereof; fuel shortages or fuel price volatility; breakdown or damage to generation or transmission facilities; insolvency of any of the SJGS owners; or changes in fundamental technology impacting the economics of operating coal-fired generation facilities. ARTICLE 15 DISPUTE RESOLUTION 15.1 Disputes shall first be discussed and resolved by representatives of each Party having the authority, through appropriate corporate or tribal resolution, if necessary, to bind the Party that they represent. Such representatives shall use their best efforts to amicably and promptly resolve the dispute. Pending resolution of any dispute, the Parties shall continue to perform their obligations hereunder. If the 14 Parties are unable to resolve any dispute within fifteen (15) calendar days of the occurrence of the event or circumstances giving rise to the dispute, either Party may give notice to the other Party that the dispute is to be submitted to binding arbitration. Such notice shall name a proposed arbitrator. In the event that the other Party does not agree to the proposed arbitrator, it shall submit the name of its proposed arbitrator, within ten (10) calendar days of said notice, and if that person is not acceptable to the Party giving the original notice, the arbitrators proposed by each Party shall, within five (5) days, select a third arbitrator. All reasonable fees and costs incurred by the arbitrators shall be split equally by the Parties and each Party shall be responsible for payment of its own attorney's fees, preparation fees, witness and expert fees, and other costs. 15.1.1 An arbitration hearing shall be held at a mutually agreed location within thirty (30) days of the appointment of the last arbitrator. At the hearing, each Party may submit statements of fact or memoranda of law as desired and the arbitrator(s) shall allow each Party to present its case, evidence and witnesses, if any, in the presence of both Parties. The arbitrator(s) shall render their decision promptly after the hearing. 15.1.2 An award of the arbitrator(s) shall be binding upon the Parties. The prevailing Party shall be entitled to confirmation of any award of the arbitrator(s) and to judgment thereon in a court of competent jurisdiction. The Tribe waives its sovereign immunity solely for the purpose of the obligations of this Article, including but not limited to the entry and enforcement of the arbitration award. This waiver of immunity is not intended, nor shall it be construed to, (a) waive the Tribe's sovereign immunity for any other purpose, or (b) extend to the benefit of any person other than the Parties to this Agreement or their successors or assigns. This waiver of immunity from suit shall not be construed as an admission of liability by the Tribe as to any claim for damages or as an agreement or willingness to pay any amount as damages absent an arbitration determination of liability, and the Tribe shall have the right to defend any such claim fully on the merits. 15.1.3 New Mexico law shall apply to the interpretation of this Agreement in connection with the resolution of disputes under this Article. 15 ARTICLE 16 AMENDMENTS This Agreement may be amended only by written instrument executed by the Parties with the same formalities and requisite approvals as this Agreement. IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed by their duly authorized representatives having the specific authority to execute this Agreement as of the date set forth below. PUBLIC SERVICE COMPANY OF NEW MEXICO By: Printed Name: Title: Date: JICARILLA APACHE TRIBE By: Printed Name: Title: Date: 16 APPROVED AS REQUIRED BY THE FEDERAL CONTRACT: UNITED STATES BUREAU OF RECLAMATION, AS THE DULY AUTHORIZED DELEGATEE OF THE SECRETARY OF THE DEPARTMENT OF THE INTERIOR OF THE UNITED STATES By: Printed Name: Title: Date: APPROVED AS REQUIRED BY ___ U.S.C. ___ BY THE UNITED STATES BUREAU OF INDIAN AFFAIRS By: Printed Name: Title: Date: 17 EX-10 4 exh1098.txt EXHIBIT 10.9.8 Exhibit No. 10.9.8. [*] indicates that the confidential portion has been omitted from this filed exhibit and filed separately with the Securities and Exchange Commission. Amendment 11 ------------ To The ------ Coal Sales Agreement -------------------- This Amendment Number Eleven to Coal Sales Agreement ("Amendment") is dated August 31, 2001, to become effective as described herein, by and among San Juan Coal Company, a Delaware corporation ("SJCC"), and Public Service Company of New Mexico, a New Mexico corporation ("PNM") and Tucson Electric Power Company, an Arizona corporation ("TEP") (collectively, the "Utilities"), (with SJCC and Utilities herein sometimes collectively referred to as "Parties"). RECITALS Whereas, SJCC and the Utilities are parties to that certain Coal Sales Agreement, dated August 18, 1980, as amended (the "CSA"); Whereas, SJCC, San Juan Transportation Company, and the Utilities are parties to the Underground Letter Agreement dated August 31, 2000 ("UGLA"); Whereas, through this amendment the Parties wish to implement a portion of the UGLA and modify the CSA; and, Whereas, the Parties intend to address other elements of the UGLA through other agreements. Now, therefore, in consideration of the promises contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, SJCC and the Utilities hereby agree as follows: AGREEMENT 1. The terms of this Amendment become effective upon execution by all Parties and satisfaction of the conditions precedent. 2. The conditions precedent to this Amendment becoming effective are: 1 Final approval of this Amendment by the San Juan Fuels Committee pursuant to the requirements of the San Juan Project Participation Agreement dated as of October 27, 1999, to be obtained no later than September 28, 2001, and written notification of such approval to SJCC by the Utilities. Execution of the Consent of Guarantor in the form attached to this Agreement and incorporated herein to be obtained no later than September 28, 2001, and provided to Utilities by SJCC. 3. Paragraph 2.4 of the CSA, "Options of Utilities" is deleted in its entirety. 4. Paragraph 9.8(b) of the CSA "Payments" is superseded and is replaced in its entirety with the following: "9.8(b) Payments. Invoices submitted by SJCC in accordance with Subparagraph 9.8(a) and any supplemental or true-up invoices shall be due and payable by Utilities on the twenty-second (22nd) day of the month succeeding the month for which such invoice is submitted, or on the twelfth (12th) day after receipt of the invoice by Utilities, whichever date is later. Payment shall be made to SJCC by electronic funds transfer to such bank account as SJCC may from time to time designate." 5. Paragraph 8.3 of the CSA, "Reserve of Stripped Coal" is superseded and is replaced in its entirety with the revised Paragraph 8.3 as follows: "8.3 Reserve of Coal - "Reserve of Coal" shall mean all coal on SJCC's premises that is mined coal in storage or un-mined coal from which the overburden has been removed." 6. A new Paragraph 17.11 "Waiver of Consequential Damages" is hereby added to Paragraph 17 "General Provisions" of the CSA. The new paragraph in its entirety follows: "17.11 Waiver of Consequential Damages - The Parties waive any recovery of consequential damages related to breach of this Agreement." 7. Paragraph 16 of the CSA, "Termination", is superseded and is replaced in its entirety with the revised Paragraph 16 as follows: "16.1 Non-Normal Conditions, Right to Cure, and Offers of Non-SJCC Coal. The Parties intend that in the effort to avoid Material Default, the provisions of this Paragraph 16.1 shall be utilized before notice of Material Default Conditions is provided pursuant to Paragraph 16.2. (a) Non-Normal Conditions. Non-Normal Conditions exist when any of the following three conditions are present: (1) The Reserve of Coal is below the level of 1.2 million Tons, 2 (2) SJCC has determined that there is a reasonable probability that the Reserve of Coal will in the near future fall below the level of 1.2 million Tons, or (3) SJCC anticipates or is experiencing any other condition that may prevent SJCC from delivering coal according to this Agreement. (b) Notice. SJCC shall provide written notice to the Utilities if any Non-Normal Conditions exist, or the Joint Committee may determine that Non-Normal Conditions exist, which shall constitute notice to SJCC and the Utilities as of the date of such written determination. (c) Prevention Due to Uncontrollable Forces. In addition to providing written notice of Non-Normal Conditions, SJCC may elect to declare that the performance is prevented by reason of uncontrollable forces in accordance with the terms of Paragraph 17.1 "Uncontrollable Forces". (d) Coal Usage Forecast. Within fifteen (15) days after receipt of notice of Non-Normal Conditions, the Utilities will review dispatch at San Juan Station and provide to SJCC an updated coal usage forecast. (e) Cure of Non-Normal Conditions. The Parties intend that cooperation among the Parties in developing and agreeing upon a Cure Plan (as defined below) is preferable to pursuing termination of this Agreement. The Parties will provide reasonable cooperation to facilitate SJCC's cure of Non-Normal Conditions to avoid Material Default while allowing the Utilities to continue operation of the San Juan Station. To initiate and effectuate cure of the Non-Normal Condition, SJCC shall do the following: (1) Provide within fifteen (15) days after notice of Non-Normal Conditions, or as otherwise agreed to by the Parties, a written cure plan to the Joint Committee describing SJCC's proposed means of curing the Non-Normal Conditions and its proposed deliveries in the interim ("Cure Plan"); (2) Within thirty (30) days after notice of Non-Normal Conditions, or as otherwise agreed to by the Parties, SJCC may provide written offers to the Utilities to supply Non-SJCC Coal. If the Non-Normal Conditions are caused by uncontrollable forces pursuant to Paragraph 17.1, then such Non-SJCC Coal will be priced [*]. If there is a dispute whether the Non-Normal Conditions are caused by uncontrollable forces, the Non-SJCC Coal will be priced [*] and will be adjusted if necessary when the dispute is resolved. If the Non-Normal Conditions are not caused by uncontrollable forces, then, the Non-SJCC Coal shall be priced at [*]. SJCC will provide quality information for the Non-SJCC Coal with the written offers and will propose the delivery schedule and quantity of Non-SJCC Coal to be supplied. 3 (3) Within fifteen (15) days after receipt of a proposed Cure Plan, the Joint Committee shall meet to consider and act on the Cure Plan. (4) Within fifteen (15) days after receipt of an offer to supply Non-SJCC Coal, the Joint Committee will meet to approve or reject the Non-SJCC Coal offer. Failure to approve the offer shall constitute its rejection. (5) For offers of Non-SJCC Coal only, SJCC will meet the revised coal minimum quality standard of at least 8700 BTU per pound measured as provided in Paragraph 5.2. (6) As part of its Cure Plan, SJCC will provide weekly written notice to the Utilities of the daily inventory levels of Reserve of Coal. (f) Rejection of Non-SJCC Coal. If the Joint Committee rejects an offer of Non-SJCC Coal that is proposed and if the price of that Non-SJCC Coal offer is [*], then the offer of Non-SJCC Coal will be credited as coal delivered for the sole purpose of determining whether a Material Default Condition exists, unless the Joint Committee agrees that the Non-Normal Condition is due to uncontrollable forces, in which case Material Default provisions are inapplicable. (g) Rejection of Non-SJCC Coal after Initial Approval. If the Utilities determine and the Joint Committee agrees that delivery of coal from a certain Non-SJCC Coal source is shown to materially impair operations at the San Juan Station, the Utilities may reject the unburned portion of that coal and, if so, SJCC shall terminate delivery of that coal. The remainder of such rejected coal shall not be credited as coal delivered for purposes of determining whether a Material Default Condition exists. (h) Termination of Non-Normal Conditions. The Non-Normal Conditions will terminate when all of the following occur: (1) The Reserve of Coal exceeds 1.2 million Tons; (2) SJCC can supply the quantities of coal required by this Agreement from the Coal Leases and/or previously acquired Non-SJCC Coal; (3) SJCC can meet normal coal quality specifications; and (4) SJCC gives written notice of the termination of Non-Normal Conditions. 4 16.2 Material Default. (a) Material Default Conditions. The existence of any of the following material default conditions ("Material Default Conditions") may result in a Material Default by SJCC: (1) Failure of SJCC to deliver coal as specified in Paragraph 3.1 such that: (i) A ten percent (10%) per month or greater shortfall in deliveries as set forth in Exhibit "D" "San Juan Generation Station" occurs in any six (6) consecutive months (as adjusted pursuant to Paragraph 16.1(f) and (g)); or (ii) A cumulative shortfall of sixty percent (60%) in deliveries as set forth in Exhibit "D" "San Juan Generation Station" occurs over any three (3) month period (as adjusted pursuant to Paragraph 16.1(f) and (g)); (2) Failure of SJCC to comply with the requirements of Paragraph 5.2 "Coal Quality" (as amended by Paragraph 16.1(e)(5) in the event that Non-SJCC Coal is supplied under Non-Normal Conditions); (3) Failure of SJCC to maintain a Reserve of Coal greater than 250,000 Tons. The occurrence of any of these three conditions is not itself a Material Default. (b) A Material Default exists when (1) one or more of the Material Default Conditions exist; (2) notice is provided pursuant to Paragraph 16.2(c) "Notice of Material Default Conditions;" and (3) SJCC fails to avoid Material Default under Paragraph 16.2(d) "Avoidance of Material Default." (c) Notice of Material Default Condition(s). SJCC shall not be in Material Default under this Agreement unless and until SJCC shall have received from Utilities written notice of one or more Material Default Conditions specifying the particulars. SJCC may seek to avoid or cure the Material Default Condition(s) pursuant to the provisions of Paragraph 16.2(d). SJCC shall not be conclusively deemed in Material Default if SJCC disputes the existence of any alleged Material Default unless and until there is a final resolution pursuant to Paragraph 14 to determine the existence or non-existence of Material Default. 5 (d) Avoidance of Material Default. SJCC can prevent any of the Material Default Conditions from becoming a Material Default by any one or more of the following actions: (1) SJCC proceeds with due diligence to cure the alleged Material Default Condition(s) within thirty (30) days of receipt of the notice of Material Default Condition(s); (2) BHP Minerals International Inc. proceeds with due diligence to cure the alleged default within thirty (30) days of receipt of the notice of Material Default Condition(s); (3) SJCC declares prevention of performance by reason of uncontrollable forces pursuant to Paragraph 17.1 "Uncontrollable Forces," and that declaration is not subsequently invalidated by arbitration; (4) SJCC gives notice of Non-Normal Conditions and operates according to a Cure Plan approved by the Joint Committee; or (5) SJCC disputes the existence of Material Default Condition(s), and there is a final resolution pursuant to Paragraph 14 "Arbitration" of this Agreement that SJCC was not in Material Default hereunder. (e) Utilities' Remedies for SJCC's Material Default. Upon a Material Default caused by the existence of a Material Default Condition that is not avoided pursuant to Paragraph 16.1(c), the Utilities shall have the following remedies: (1) The Utilities may terminate this Agreement for Material Default. Upon termination for Material Default, the Utilities shall have the options set forth in Paragraph 16.3 "Termination." (2) Only in the event of an emergency situation as provided in Paragraph 13.1, Utilities or Utilities' agents may, in lieu of seeking termination or any other remedy, go upon SJCC's facilities, use SJCC's equipment to mine coal therefrom, and deliver such coal to the delivery points. The compensation to be paid by Utilities to SJCC for such use of SJCC's equipment shall be agreed upon by the Joint Committee. Such operations by Utilities shall terminate when SJCC gives notice that SJCC is able to assume normal deliveries. 6 (3) In addition to the rights provided in Paragraph 16.3 to termination and the limited right to mine, Utilities shall have any other remedies provided by law, subject to the waiver of consequential damages in Paragraph 17.11 of this Agreement. 16.3 Termination. (a) Options of Utilities Upon Termination. Upon termination of this Agreement for Material Default, in addition to other remedies provided in Paragraph 16.2(e) "Remedies," the Utilities shall have the option to: (i) Acquire SJCC's rights, title and interest in and to any or all of SJCC's plant and capital equipment used by SJCC in carrying out its obligations under this Agreement and the Coal Leases and other leases in the SJCC premises including all SJCC's permits and reclamation bonds, paying SJCC therefore in cash the greater of the fair market value of SJCC's plant and capital equipment, and Coal Leases and other leases in the SJCC premises as determined by the Joint Committee, or SJCC's book cost net of depreciation of said plant and capital equipment, and the net value of the acquisition cost of the Coal Leases and other leases in the SJCC premises; (ii) Require SJCC to dispose of any or all of SJCC's plant and capital equipment used by SJCC in carrying out its obligations under this Agreement, and interest in the Coal Leases and other leases in the SJCC premises including all SJCC's permits and reclamation bonds, for cash at prevailing market prices and to pay SJCC all costs of disposal plus the amount, if any, by which SJCC's book cost net of depreciation of said plant and capital equipment, and the net value of the acquisition cost of the Coal Leases and other leases in the SJCC premises exceed the amount received by SJCC on account of the disposal thereof; or (iii) Exercise neither of the above options, in which case SJCC shall retain such property interests as are necessary for the time required to satisfy all reclamation and other obligations, including, without limitation, the obligations pursuant to Paragraph 8.7 "Reclamation". (b) Notice of Election. Within thirty (30) days after termination of this Agreement, the Joint Committee will determine fair market value and book value of SJCC's plant, capital equipment and the Coal Leases and other leases in the SJCC premises, 7 including all of SJCC's permits and reclamation bonds. The Joint Committee will not disband until it determines such values. Within thirty (30) days after receipt of the Joint Committee determination of value, the Utilities shall notify SJCC in writing which of the above three options the Utilities elect. In the event the Utilities elect option (a)(i), SJCC shall, within thirty (30) days of written notice of said election, deliver to Utilities a sufficient bill of sale or other appropriate instrument of conveyance, together with an invoice showing in reasonable detail the amount due, whereupon Utilities shall, within sixty (60) days thereafter, remit to SJCC the amount due. In the event Utilities shall elect option (a)(ii), SJCC shall undertake to promptly dispose of its plant and capital equipment, and interest in the Coal Leases and other leases in the SJCC premises, including all of SJCC's permits and reclamation bonds, and shall thereafter invoice Utilities for the amount due SJCC (said invoice to show in reasonable detail the amount, if any, received as a result of said disposition, SJCC's book cost (net of depreciation) and the balance due), whereupon Utilities shall, within sixty (60) days of receipt of said invoice, remit to SJCC the amount due SJCC. (c) Terms of Transfer. Any transfer of all of SJCC's right, title and interest in and to the Coal Leases and other leases in the SJCC premises , including all of SJCC's permits and reclamation bonds shall be by an appropriate instrument of conveyance, with special warranty covenants, subject to necessary consents, and such assignment and/or transfer will become effective at the earliest possible time after the termination of this Agreement or extension thereof. (d) Liabilities Upon Termination. Upon termination the Utilities shall assume all financial obligations, if any, attributable to (1) The then remaining term of the Assignment Agreement dated October 30, 1979, originally between Cimarron Coal Company and Western Coal Company and assigned to SJCC, as amended and modified; and, 2) All leases and subleases that are Coal Leases and other leases in the SJCC premises as of August 30, 2000 (including private royalty obligations or retained interests). In addition, after termination of this Agreement, the Utilities remain obligated to pay for all surface reclamation associated with disturbance on the SJCC premises resulting in any way from the supply of coal to the San Juan Station prior to termination of this Agreement (including reclamation of surface mining and the surface effects of underground mining) and related liabilities, obligations and costs. 8 16.4 Expiration. (a) In the event the Parties fail to agree to extend this Agreement pursuant to Paragraph 2.3, Parties have the obligation to negotiate diligently and in good faith with a view to concluding a new or revised agreement to be effective commencing at the expiration of this Agreement. (b) Upon expiration as provided in Paragraph 2, and in the event the Parties have not reached agreement pursuant to Paragraph 16.4(a) or upon expiration of this Agreement (or any extension or revision hereof) for any other reason, the Utilities may elect one of the options identified in Paragraph 16.3(a)(i), Paragraph 16.3(a)(ii) and Paragraph 16.3(a)(iii) of this Agreement. (c) Notice of Election. Within thirty (30) days after expiration of this Agreement, the Joint Committee will determine fair market value and book value of SJCC's plant, capital equipment and the Coal Leases, including all of SJCC's permits and reclamation bonds. The Joint Committee will not disband until it determines such values. Within thirty (30) days after receipt of the Joint Committee determination of value, the Utilities shall notify SJCC in writing which of the above three options the Utilities elect. In the event the Utilities elect option 16.3 (a)(i), SJCC shall, within thirty (30) days of written notice of said election, deliver to Utilities a sufficient bill of sale or other appropriate instrument of conveyance, together with an invoice showing in reasonable detail the amount due, whereupon Utilities shall, within sixty (60) days thereafter, remit to SJCC the amount due. In the event Utilities shall elect option 16.3 (a)(ii), SJCC shall undertake to promptly dispose of its plant and capital equipment, and interest in the Coal Leases, including all of SJCC's permits and reclamation bonds, and shall thereafter invoice Utilities for the amount due SJCC (said invoice to show in reasonable detail the amount, if any, received as a result of said disposition, SJCC's book cost (net of depreciation) and the balance due), whereupon Utilities shall, within sixty (60) days of receipt of said invoice, remit to SJCC the amount due SJCC. (d) Terms of Transfer and Liabilities Upon Expiration. Any transfer of all of SJCC's rights, title and interest in and to the Coal Leases and other leases in the SJCC premises, including all of SJCC's permits and reclamation bonds, shall be by an appropriate instrument of conveyance, with special warranty covenants, subject to necessary consents, and such assignment and/or transfer will become effective at the earliest possible time after the expiration of this Agreement or extension thereof. After expiration of this Agreement, the Utilities remain obligated to pay for all reclamation and related liabilities, obligations and costs pursuant to Paragraph 8.7 "Reclamation". 8. Except as expressly amended herein, the CSA is in all respects hereby confirmed and ratified. 9 IN WITNESS WHEREOF, SJCC, and the Utilities, by their duly authorized representatives, have entered into this Amendment. PUBLIC SERVICE COMPANY OF NEW MEXICO By: /s/ Patrick J. Goodman 8/29/01 ---------------------------------------- ------- Patrick J. Goodman, Vice President Date TUCSON ELECTRIC POWER COMPANY By: /s/ Kevin Larson 8/31/01 ------------------------------------------------- ------- Kevin Larson, Vice President Date SAN JUAN COAL COMPANY By: /s/ John W. Grubb 8/29/01 ---------------------------------------- ------- John W. Grubb, President Date 10 EX-10 5 exh1083.txt EXHIBIT 10.83 Exhibit No. 10.83 [*] indicates that the confidential portion has been omitted from this filed exhibit and filed separately with the Securities and Exchange Commission. Transportation Agreement ------------------------ Buy Out Agreement ----------------- Among San Juan Transportation Company Public Service Company of New Mexico Tucson Electric Power Company Table of Contents ----------------- Section 0 - Parties and Recitals.............................................1 Section 1 - Definitions and Term.............................................1 1.1 EFFECTIVE DATE...................................................1 1.2 OUTSTANDING SJTA OBLIGATIONS.....................................1 1.3 SJTC COSTS.......................................................1 1.4 TERM.............................................................2 Section 2 - Conditions Precedent, Representations and Warranties.............2 2.1 CONDITIONS PRECEDENT.............................................2 2.2 REPRESENTATIONS AND WARRANTIES...................................2 Section 3 - SJTC Compensation................................................2 3.1 SJTA BUY OUT VALUE...............................................2 3.2 INFLATION - DEFLATION ADJUSTMENT.................................3 3.3 PAYMENT OF TBOV..................................................3 3.4 PAYMENT OF SJTC COSTS............................................4 Section 4 - SJTA Termination.................................................5 4.1 SJTA TERMINATION.................................................5 Section 5 - SJTC Obligations.................................................5 5.1 SJTC OBLIGATIONS.................................................5 Section 6 - Dispute Resolution...............................................6 6.1 MATTERS TO BE ARBITRATED; NOTICE OF CLAIMS AND DEFENSES; PARTY ARBITRATOR DESIGNATION.....................................6 6.2 ARBITRATORS; SELECTION OF NEUTRAL ARBITRATOR.....................6 6.3 ARBITRATION HEARINGS, PROCEDURES AND TIMING......................6 6.4 CHOICE OF LAW....................................................6 6.5 AWARD AND ENFORCEMENT............................................7 6.6 PERFORMANCE PENDING ARBITRATION DECISION.........................7 6.7 DEFINITION OF "PARTIES" FOR THIS SECTION.........................7 Page i Section 7 - Joint Committee..................................................7 7.1 PURPOSE..........................................................7 7.2 DESIGNATION......................................................7 7.3 AUTHORITY........................................................7 7.4 DECISIONS........................................................8 7.5 RELATIONSHIP TO ARBITRATION......................................8 Section 8 - General Provisions...............................................8 8.1 CONFIDENTIALITY..................................................8 8.2 JOINT AND SEVERAL................................................8 8.3 ENTIRE AGREEMENT.................................................8 8.4 SUCCESSORS AND ASSIGNS...........................................9 8.5 CONSTRUCTION.....................................................9 8.6 WAIVER OF CONSEQUENTIAL DAMAGES..................................9 8.7 NOTICES..........................................................9 Section 9 - Signatures......................................................11 Attachment 1 Guarantee Page ii Section 0 - Parties and Recitals -------------------------------- This Transportation Agreement Buy Out Agreement ("Agreement") is dated August 31, 2001, to become effective on December 31, 2002, as provided herein, by and between San Juan Transportation Company, a Delaware corporation ("SJTC"), Public Service Company of New Mexico, a New Mexico corporation ("PNM"), and Tucson Electric Power Company, an Arizona corporation ("TEP") (PNM and TEP are referred to collectively as "Utilities"), (with SJTC and Utilities herein sometimes collectively referred to as "Parties"). Whereas, SJTC and Utilities are parties to the Transportation Agreement dated April 30, 1984 between SJTC and Utilities, as amended ("SJTA"), which has a term through 2017; Whereas, Utilities have ongoing obligations under the SJTA; Whereas, SJTC and the Utilities desire to terminate the SJTA and provide compensation to SJTC for the Utilities' remaining obligations under the SJTA; Whereas, SJTC, San Juan Coal Company ("SJCC"), and Utilities are parties to the Underground Letter Agreement dated August 31, 2000 ("UG Letter Agreement"); and, Whereas, SJCC and Utilities are parties to the Underground Coal Sales Agreement ("UG-CSA") dated August 31, 2001. NOW, THEREFORE, in consideration of the terms, covenants and agreements contained in this Agreement, Utilities jointly and severally agree with SJTC as follows: Section 1 - Definitions and Term -------------------------------- 1.1 Effective Date Subject to Section 2.1 "Conditions Precedent", the Effective Date of this Agreement shall be December 31, 2002. 1.2 Outstanding SJTA Obligations "Outstanding SJTA Obligations" shall be defined as any payments, costs, audit adjustments (including 3rd party audits), or other obligations arising from or related to performance under the SJTA prior to the SJTA termination. 1.3 SJTC Costs "SJTC Costs" shall be defined as: A) Any and all rentals, royalties, overriding royalties, other retained interests, charges, fees and all other payments paid or incurred by SJTC in connection with this Agreement; B) Any Outstanding SJTA Obligations; and, C) Any and all actual costs incurred by SJTC (including reasonable attorney fees and expenses) relating to all claims other than those between Utilities and SJTC which arise from the payment of TBOV as defined in Section 3.1 "SJTA Buy Out Value". 1 1.4 Term This Agreement shall terminate after all payments have been received in full by SJTC in accordance with the terms of this Agreement and all obligations under this Agreement have been satisfied or otherwise resolved pursuant to Section 6 "Dispute Resolution". Section 2 - Conditions Precedent, Representations and Warranties ---------------------------------------------------------------- 2.1 Conditions Precedent The Conditions Precedent to this Agreement becoming effective are: A) Satisfaction of the conditions precedent contained in the UG-CSA. B) Final approval of this Agreement by the San Juan Fuels Committee pursuant to the requirements of the San Juan Project Participation Agreement dated as of October 27, 1999, to be obtained no later than September 28, 2001, and written notification of such approval to SJTC by the Utilities. C) Execution of the Guarantee by the Guarantor in the form attached to this Agreement as Attachment 1 and incorporated herein, to be obtained no later than September 28, 2001, and provided to Utilities by SJTC. 2.2 Representations and Warranties As of the execution of this Agreement and subject to satisfaction of the applicable conditions precedent described in this Agreement, each party warrants and represents that: A) It is a corporation duly organized and in good standing in its state of incorporation and is qualified to do business and is in good standing in those states where necessary in order to carry out the purposes of this Agreement; B) It has the capacity to enter into and perform this Agreement and all transactions contemplated in this Agreement, and that all corporate actions required to authorize it to enter into and perform this Agreement have been taken properly; and C) This Agreement has been duly executed and delivered by it and is valid and binding upon it in accordance with its terms. Section 3 - SJTC Compensation ----------------------------- 3.1 SJTA Buy Out Value The Utilities shall pay to SJTC [*] adjusted per Section 3.2 "Inflation - Deflation Adjustment" ("TBOV"), on December 31, 2002, to buy out the value of the SJTA Capital Investment Element and to extinguish any further obligations under the SJTA. 2 3.2 Inflation - Deflation Adjustment A) The amount of [*] will be adjusted for inflation according to the following formula: TBOV = [*] x D1 / D0 (1 & 0 are subscripts) D1 and D0 are defined herein. In no event shall the inflation-deflation adjustment cause TBOV to be less than [*]. B) The "Inflation Index", calculated to three decimal places, shall be equal to the sum of sixty-five percent (65%) times the "Producer Price Index- Commodities for Construction Machinery and Equipment (Series Id WPU112)" not seasonally adjusted, as published by the United States Department of Labor, Bureau of Labor Statistics ("Index"), plus thirty-five percent (35%) times the "Implicit Price Deflator, Gross Domestic Product", as published by the United States Department of Commerce, Bureau of Economic Analysis ("Deflator"). i D0 shall be the Inflation Index calculated using the most recently published values for June 2000, for the Index and Deflator described above. ii D1 shall be the Inflation Index calculated using the most recently published values available for the date when the payment is due, for the Index and Deflator described above. In the event that there is a revision of a base index figure, the base index figure will be revised in accordance with pertinent published instructions regarding such revision, or if such instructions are not published, the base index figure will be revised in a manner, which fairly reflects the revision. In the event that publication of any of the indices specified for use under this Section 3.2 (B) should be discontinued or in the event the items or categories upon which such published index is based should be so modified or changed as to make the further use of such index inequitable, the Parties agree to develop a mutually acceptable substitute index (either published or compiled or arranged by the Parties). 3.3 Payment of TBOV A) There will not be an invoice generated by SJTC for payment made pursuant to Section 3.1. B) Utilities agree to make an electronic funds transfer of TBOV due to SJTC, and all applicable taxes, to SJTC's nominated account (to be nominated in writing by SJTC at least 60 days before the payment date) on or before the payment date described herein. Applicable taxes shall include any and all taxes (including without limitation gross income, gross receipts, value added, sales, use, occupation, franchise, personal property, stamp and other taxes), levies, imposts, duties, charges or withholdings of any nature whatsoever, together with any interest thereon (any of the foregoing fees, taxes and interest being for purposes hereof called "taxes") imposed by any sovereign political or 3 governmental authority or taxing authority upon or in connection with SJTC's operation and with any activities and transactions under this Agreement (including reimbursements for SJTC Costs as described hereunder) excepting only taxes which are measured by net income (other than any such taxes measured by net income which are imposed in lieu of taxes measured by gross income and gross receipts). C) Utilities shall provide SJTC with documentation of the Inflation Index used to determine the payment amount with notification of the electronic funds transfer. 3.4 Payment of SJTC Costs A) Invoicing and Payment SJTC will invoice the Utilities for SJTC Costs. Invoices submitted by SJTC shall be due and payable by Utilities on the twenty-second (22nd) day of the month succeeding the month for which such invoice is submitted, or on the twelfth (12th) day after receipt of the invoice by Utilities, whichever date is later. Payment shall be made to SJTC by electronic funds transfer to such bank account as SJTC may from time to time designate. B) Disputed Invoices In case any portion of any invoice concerning SJTC Costs is disputed, the undisputed amount shall be paid when due; provided however, that Utilities may also pay the disputed portion of such invoice without thereby waiving their right to contest such disputed portion. Disputed invoices for SJTC Costs shall be referred initially to the Joint Committee for resolution. C) Failure to Pay In the event Utilities fail to pay any amount due and not in bona fide dispute, SJTC shall be paid interest on all amounts owing under any invoice submitted hereunder which are not paid when due and payable, with said interest to be calculated at the Prime Rate as published in the Wall Street Journal for corporate loans posted by at least 75% of the nation's largest banks (or its equivalent) plus three percent (3%) but not in excess of the maximum rate of interest permitted by law and to be paid for the actual number of days elapsed since the invoice was due and payable. This right shall not be deemed an exclusive right or remedy. D) Audits SJTC will keep books, records and accounts necessary to show all information required for purposes of this Section 3.4. Upon Utilities' request, SJTC shall supply Utilities, by report and/or with actual source documents, the information reasonably 4 necessary to verify any invoice for SJTC Costs issued pursuant to this Agreement; provided, however, that SJTC shall not be required to disclose information which in the opinion of SJTC is of a confidential nature due to the relationship of such information to SJTC's existing or contemplated operations. In the event Utilities and SJTC are unable to agree that the invoice is calculated correctly, a verification of such invoice shall be prepared and certified by a nationally recognized firm of certified public accountants, to be selected by Utilities from a list of three (3) such firms submitted by SJTC, such verification to set forth all data reasonably necessary to verify that the invoice is calculated correctly. The findings of said verification shall be accepted by both Utilities and SJTC as final and binding with respect to that invoice. The accounting firm selected for any such verification shall be bound not to disclose and shall treat as confidential any and all proprietary information of SJTC furnished to or examined by such firm in connection with such audit. It is understood that such verification shall not provide Utilities with nor entitle Utilities access to SJTC's books or records. If any such verification discloses that a calculation error has occurred and that, as a result thereof, an amount is due to one or the other party, such amount shall promptly be paid to whom it is owed; provided, however, if there is a dispute relating to the validity of a charge or adequacy of a payment either party may submit such dispute to the Joint Committee. All expenses of any such requested verification shall be paid by Utilities. Invoices which are not contested by either party within twenty-four (24) months from the date of the Invoice shall be deemed to be correct and will not thereafter be subject to verification. Section 4 - SJTA Termination ---------------------------- 4.1 SJTA Termination Upon receipt of the TBOV payment by SJTC as adjusted and in consideration of the terms and conditions set forth in this Agreement, the SJTA and the associated Guarantee by BHP Minerals International Inc. are terminated and all obligations under the SJTA are satisfied. Section 5 - SJTC Obligations ---------------------------- 5.1 SJTC Obligations SJTC shall use reasonable efforts consistent with law to minimize claims for costs referenced in Section 1.3(A) and to manage costs referenced in Section 1.3(C). 5 Section 6 - Dispute Resolution ------------------------------ 6.1 Matters To Be Arbitrated; Notice of Claims and Defenses; Party Arbitrator Designation Either party may demand final and binding arbitration of any dispute, claim or controversy arising out of or relating to this Agreement, performance or actions pursuant to this Agreement, or concerning the interpretation of this Agreement (whether such matters sound in contract, tort or otherwise and including without limitation repudiation, illegality, and/or fraud in the inducement) by giving written notice to the other party of all claims it desires to submit to arbitration; provided, however, that matters within the authority of the Joint Committee must be presented first to that committee for consideration. Disputes regarding the payment of TBOV shall be immediately subject to arbitration in accordance with this section. The notice shall include: (a) the demanding party's designation of a party arbitrator; and (b) a detailed statement of the facts and theories supporting the claims. The party on whom the arbitration demand is served shall have thirty days from receipt of the notice to respond in writing to the demand and to submit any additional claims it wishes to submit to arbitration at the same time. The response also shall include: (a) the designation of the party arbitrator for that party; and (b) a detailed statement of the facts and theories supporting the claims and/or defenses asserted. The party originally demanding arbitration shall reply in writing to any additional claims submitted within ten days from the receipt of response. 6.2 Arbitrators; Selection of Neutral Arbitrator Any party who fails to designate timely its party arbitrator shall forfeit its right to designate an arbitrator. If only one arbitrator is timely designated, that single arbitrator shall hear the dispute. If two arbitrators are timely designated, those arbitrators shall, within thirty days, either agree on the appointment of a third, disinterested arbitrator knowledgeable as to the subject matter involved in the arbitration or petition the Chief Judge of the United States District Court for the District of New Mexico for the appointment of a third arbitrator. The parties shall be equally liable for the reasonable fees and expenses of the neutral arbitrator hearing the dispute. The parties shall be responsible for the fees and expenses of their respective party-appointed arbitrator. 6.3 Arbitration Hearings, Procedures and Timing All reasonable efforts will be made to hold a hearing on the claims submitted within sixty days after the appointment of the last arbitrator. In conducting the hearing, the arbitrators are directed, where feasible and where not inconsistent with the provisions of this paragraph, to adhere to the then-existing American Arbitration Association procedures and rules relating to commercial disputes. Unless otherwise agreed by the parties, the hearing shall be held in Farmington, New Mexico. 6 6.4 Choice of Law The arbitrators shall apply the laws of the State of New Mexico. 6.5 Award and Enforcement The decision or award of the arbitrators shall be given in writing within thirty days after the conclusion of the hearing. The arbitrators are authorized to award money damages, injunctive and declaratory relief and/or specific performance, if such relief in their opinion is appropriate. In any arbitration, each party shall bear its own costs, expenses, and attorneys' fees. The arbitrators do not have authority to award costs, expenses, or attorneys' fees to the prevailing party. The award or decision of the arbitrators shall be subject to review or enforcement in accordance with the New Mexico Uniform Arbitration Act, NMSA 1978 ss.ss. 44-7-1 et seq. Any party shall be entitled to recover reasonable attorneys' fees and costs incurred in enforcing any arbitration award or decision made pursuant to the arbitration provisions of this Agreement. 6.6 Performance Pending Arbitration Decision During the arbitration, unless otherwise ordered by the arbitrators, the parties agree to continued performance under this Agreement. 6.7 Definition of "Parties" for this Section For purposes of this Section 6, the Utilities shall be considered a single party. Specifically, and by example, the Utilities must act collectively to select their party arbitrator under Section 6.2 "Arbitrators; Selection of Neutral Arbitrator". Section 7 - Joint Committee --------------------------- 7.1 Purpose The intent of the Parties in providing for a Joint Committee is to establish an orderly and continuing means of dealing with matters that may arise from time to time in carrying out the provisions of this Agreement. The Joint Committee shall have four (4) members. 7.2 Designation During the term of this Agreement, SJTC will, by notice to Utilities, designate two (2) individuals as its representatives on the Joint Committee, and Utilities will, by notice to SJTC, designate two (2) individuals as their representatives on the Joint Committee; and each such representative shall be authorized by the party(ies) by whom he is designated to act on its (their) behalf with respect to matters herein specified to be responsibilities of the Joint Committee. A representative may not delegate his responsibilities to others, but Utilities, or SJTC, may designate an alternate to act when said representative is unavailable. Either Utilities, or SJTC, by notice to the other, may change the designation of its (their) representatives. 7.3 Authority The Joint Committee shall have authority and responsibility to address disputes arising from or related to this Agreement other than disputes regarding the payment of TBOV. The Joint Committee shall not have any authority with respect to disputes regarding the payment of TBOV and such disputes shall be immediately subject to arbitration. 7 7.4 Decisions Decisions by the Joint Committee shall require the unanimous approval of all representatives of the Joint Committee and shall be evidenced by the signatures of all said representatives. 7.5 Relationship to Arbitration In case agreement should not be reached among the representatives of the Joint Committee as to any of the matters referred to in Section 7.3 "Authority" as responsibilities of the Joint Committee, such matters shall be forthwith submitted to and determined by arbitration as provided for in Section 6 "Dispute Resolution". Section 8 - General Provisions ------------------------------ 8.1 Confidentiality The terms and conditions, including those dealing with compensation, set forth in this Agreement are considered by Utilities and SJTC to be confidential and proprietary information and none of the parties shall disclose any such information to any third party other than the attorneys, auditors and agents of Utilities, other owners of the San Juan Station, and SJTC, without the advance written consent of the other parties; provided however, disclosure may be made without advance consent where, in the opinion of counsel, such disclosure may be required by order of court or regulatory agency, law or regulation or in connection with judicial or administrative proceedings involving a party hereto, in which event the party to make such disclosure shall advise the other parties in advance as soon as possible and cooperate to the maximum extent practicable to minimize the disclosure of any such information, including, where practicable, deletion of portions of this Agreement relating to compensation, including, Section 3 "SJTC Compensation". Utilities shall maintain with the owners of the San Juan Station other than the Utilities written confidentiality agreements that are acceptable to SJTC prior to the disclosure of the terms of this Agreement. 8.2 Joint and Several The Utilities' duties and obligations under this Agreement shall be joint and several. 8.3 Entire Agreement This Agreement supersedes all prior agreements and representations between the Parties, whether written or oral, with respect to the subject matter of this Agreement and is intended as a complete and exclusive statement of the terms of the agreement between the Parties with respect to the subject matter. Except as specifically set forth in this Agreement, no representations have been made to induce any of the Parties to enter into this Agreement. 8 8.4 Successors and Assigns This Agreement and all of the rights and obligations of the Parties described shall extend to and be binding upon, and shall inure to the benefit of, the respective successors and assigns of the respective Parties. 8.5 Construction The terms and conditions of this Agreement are the result of negotiation and drafting on an equal footing by the Parties and their legal counsel. This Agreement shall be construed evenhandedly and without favor or predisposition to any party. 8.6 Waiver of Consequential Damages. SJTC and the Utilities waive any recovery of consequential damages related to the breach of this Agreement. 8.7 Notices A) Any notice, demand or request provided for in this Agreement, or given or made in connection with this Agreement shall be in writing, signed by an officer of the party giving such notice and shall be deemed to be properly and sufficiently given or made if sent by registered or certified mail, and if to SJTC, addressed as follows: San Juan Transportation Company 300 West Arrington, Suite 200 Farmington, NM 87401 Attention: President with a copy addressed as follows: San Juan Transportation Company Post Office Box 155 Fruitland, NM 87416 Attention: Vice President and if to Utilities, addressed as follows: Public Service Company of New Mexico Alvarado Square Albuquerque, NM 87158 Attention: Corporate Secretary and Tucson Electric Power Company Post Office Box 711 Tucson, AZ 85702 Attention: Secretary 9 B) Any party hereto may change its address for notice by so advising the other Parties hereto in accordance with the provisions of this Section 8.7. Any notice given in accordance with the provisions of this Section 8.7 shall be deemed effectively given as of the date of its deposit with the United States Postal Service. 10 Section 9 - Signatures IN WITNESS WHEREOF, SJTC and the Utilities, by their duly authorized representatives, have entered into this Agreement. PUBLIC SERVICE COMPANY OF NEW MEXICO By: /s/ Patrick J. Goodman 8/29/01 ---------------------------------------- ------- Patrick J. Goodman, Vice President Date TUCSON ELECTRIC POWER COMPANY By: /s/ Kevin Larson 8/31/01 ------------------------------------------------- ------- Kevin Larson, Vice President Date SAN JUAN TRANSPORTATION COMPANY By: /s/ John W. Grubb 8/29/01 ---------------------------------------- ------- John W. Grubb, President Date 11 EX-10 6 exh1084.txt EXHIBIT 10.84 Exhibit No. 10.84 [*] indicates that the confidential portion has been omitted from this filed exhibit and filed separately with the Securities and Exchange Commission. Coal Sales Agreement -------------------- Buy Out Agreement ----------------- Among San Juan Coal Company Public Service Company of New Mexico Tucson Electric Power Company Table of Contents ----------------- Section 0 - Parties and Recitals..............................................1 Section 1 - Definitions and Term..............................................1 1.1 EFFECTIVE DATE....................................................1 1.2 OUTSTANDING CSA OBLIGATIONS.......................................1 1.3 SJCC COSTS........................................................1 1.4 TERM..............................................................2 Section 2 - Conditions Precedent, Representations and Warranties..............2 2.1 CONDITIONS PRECEDENT..............................................2 2.2 REPRESENTATIONS AND WARRANTIES....................................2 Section 3 - Coal Reserves Bought Out..........................................2 3.1 SAN JUAN MINE SURFACE RESERVES....................................2 3.2 LA PLATA MINE SURFACE RESERVES....................................3 Section 4 - SJCC Compensation.................................................3 4.1 CSA BUY OUT VALUE.................................................3 4.2 INFLATION - DEFLATION ADJUSTMENT..................................3 4.3 PAYMENT OF CBOV...................................................4 4.4 PAYMENT OF SJCC COSTS.............................................4 Section 5 - CSA Termination...................................................5 5.1 CSA TERMINATION...................................................5 Section 6 - SJCC Obligations..................................................6 6.1 SJCC OBLIGATIONS..................................................6 Section 7 - Dispute Resolution................................................6 7.1 MATTERS TO BE ARBITRATED; NOTICE OF CLAIMS AND DEFENSES; PARTY ARBITRATOR DESIGNATION......................................6 7.2 ARBITRATORS; SELECTION OF NEUTRAL ARBITRATOR......................6 7.3 ARBITRATION HEARINGS, PROCEDURES AND TIMING.......................7 7.4 CHOICE OF LAW.....................................................7 i 7.5 AWARD AND ENFORCEMENT.............................................7 7.6 PERFORMANCE PENDING ARBITRATION DECISION..........................7 7.7 DEFINITION OF "PARTIES" FOR THIS SECTION..........................7 Section 8 - Joint Committee...................................................7 8.1 PURPOSE...........................................................7 8.2 DESIGNATION.......................................................7 8.3 AUTHORITY.........................................................8 8.4 DECISIONS.........................................................8 8.5 RELATIONSHIP TO ARBITRATION.......................................8 Section 9 - General Provisions................................................8 9.1 CONFIDENTIALITY...................................................8 9.2 JOINT AND SEVERAL.................................................9 9.3 ENTIRE AGREEMENT..................................................9 9.4 SUCCESSORS AND ASSIGNS............................................9 9.5 CONSTRUCTION......................................................9 9.6 WAIVER OF CONSEQUENTIAL DAMAGES...................................9 9.7 NOTICES...........................................................9 Section 10 - Signatures......................................................11 List of Attachments and Exhibits Attachment 1: Guarantee Exhibit 1: San Juan Mine Surface Reserves Exhibit 2: La Plata Mine Surface Reserves ii Section 0 - Parties and Recitals -------------------------------- This Coal Sales Agreement Buy Out Agreement ("Agreement") is dated August 31, 2001, to become effective on December 31, 2002, as provided herein, by and between San Juan Coal Company, a Delaware corporation ("SJCC"), Public Service Company of New Mexico, a New Mexico corporation ("PNM"), and Tucson Electric Power Company, an Arizona corporation ("TEP") (PNM and TEP are referred to collectively as "Utilities"), (with SJCC and Utilities herein sometimes collectively referred to as "Parties"). Whereas, SJCC and Utilities are parties to the Coal Sales Agreement dated August 18, 1980 between SJCC and Utilities, as amended ("CSA"), which has a term through 2017; Whereas, Utilities have ongoing obligations under the CSA; Whereas, SJCC and the Utilities desire to terminate the CSA and provide compensation to SJCC for the Utilities' remaining obligations under the CSA; Whereas, SJCC, San Juan Transportation Company, and Utilities are parties to the Underground Letter Agreement dated August 31, 2000 ("UG Letter Agreement"); and, Whereas, SJCC and Utilities are parties to the Underground Coal Sales Agreement ("UG-CSA") dated August 31, 2001. NOW, THEREFORE, in consideration of the terms, covenants and agreements contained in this Agreement, Utilities jointly and severally agree with SJCC as follows: Section 1 - Definitions and Term -------------------------------- 1.1 Effective Date Subject to Section 2.1 "Conditions Precedent", the Effective Date of this Agreement shall be December 31, 2002. 1.2 Outstanding CSA Obligations "Outstanding CSA Obligations" shall be defined as any payments, costs, audit adjustments (including 3rd party audits), or other obligations arising from or related to performance under the CSA prior to the CSA termination. 1.3 SJCC Costs "SJCC Costs" shall be defined as: A) Any and all rentals, royalties, overriding royalties, other retained interests, charges, fees and all other payments paid or incurred by SJCC in connection with this Agreement; B) Any Outstanding CSA Obligations; and, C) Any and all actual costs incurred by SJCC (including reasonable attorney fees and expenses) relating to all claims other than those between Utilities and SJCC which arise from the payment of CBOV as defined in Section 4.1 "CSA Buy Out Value". 1 1.4 Term This Agreement shall terminate after all payments have been received in full by SJCC in accordance with the terms of this Agreement and all obligations under this Agreement have been satisfied or otherwise resolved pursuant to Section 7 "Dispute Resolution". Section 2 - Conditions Precedent, Representations and Warranties ---------------------------------------------------------------- 2.1 Conditions Precedent The Conditions Precedent to this Agreement becoming effective are: A) Satisfaction of the conditions precedent contained in the UG-CSA. B) Final approval of this Agreement by the San Juan Fuels Committee pursuant to the requirements of the San Juan Project Participation Agreement dated as of October 27, 1999, to be obtained no later than September 28, 2001, and written notification of such approval to SJCC by the Utilities. C) Execution of the Guarantee by the Guarantor in the form attached to this Agreement as Attachment 1 and incorporated herein, to be obtained no later than September 28, 2001, and provided to Utilities by SJCC. 2.2 Representations and Warranties As of the execution of this Agreement and subject to satisfaction of the applicable conditions precedent described in this Agreement, each party warrants and represents that: A) It is a corporation duly organized and in good standing in its state of incorporation and is qualified to do business and is in good standing in those states where necessary in order to carry out the purposes of this Agreement; B) It has the capacity to enter into and perform this Agreement and all transactions contemplated in this Agreement, and that all corporate actions required to authorize it to enter into and perform this Agreement have been taken properly; and C) This Agreement has been duly executed and delivered by it and is valid and binding upon it in accordance with its terms. Section 3 - Coal Reserves Bought Out ------------------------------------ 3.1 San Juan Mine Surface Reserves The San Juan Mine reserves shown for illustrative purposes on Exhibit 1 "San Juan Mine Surface Reserves" (attached and incorporated by reference) are bought out by this Agreement. SJCC shall maintain records sufficient to identify these reserves. 2 3.2 La Plata Mine Surface Reserves The La Plata Mine reserves shown for illustrative purposes on Exhibit 2 "La Plata Mine Surface Reserves" (attached and incorporated by reference) are bought out by this Agreement. SJCC shall maintain records sufficient to identify these reserves. Section 4 - SJCC Compensation ----------------------------- 4.1 CSA Buy Out Value The Utilities shall pay to SJCC [*], adjusted per Section 4.2 "Inflation - Deflation Adjustment" ("CBOV"), on December 31, 2002, to buy out the value of the La Plata and Fruitland Capital Investment Elements and to extinguish any further obligations under the CSA. 4.2 Inflation - Deflation Adjustment A) The amount of [*] will be adjusted for inflation according to the following formula: CBOV = [*] x D1 / D0 (1 and 0 are subscripts) D1 and D0 are defined herein. In no event shall the inflation-deflation adjustment cause CBOV to be less than [*]. B) The "Inflation Index", calculated to three decimal places, shall be equal to the sum of sixty-five percent (65%) times the "Producer Price Index- Commodities for Construction Machinery and Equipment (Series Id WPU112)" not seasonally adjusted, as published by the United States Department of Labor, Bureau of Labor Statistics ("Index"), plus thirty-five percent (35%) times the "Implicit Price Deflator, Gross Domestic Product", as published by the United States Department of Commerce, Bureau of Economic Analysis ("Deflator"). 1) D0 shall be the Inflation Index calculated using the most recently published values for June 2000, for the Index and Deflator described above. 2) D1 shall be the Inflation Index calculated using the most recently published values available for the date when the payment is due, for the Index and Deflator described above. In the event that there is a revision of a base index figure, the base index figure will be revised in accordance with pertinent published instructions regarding such revision, or if such instructions are not published, the base index figure will be revised in a manner, which fairly reflects the revision. 3 In the event that publication of any of the indices specified for use under this Section 4.2 (B) should be discontinued or in the event the items or categories upon which such published index is based should be so modified or changed as to make the further use of such index inequitable, the Parties agree to develop a mutually acceptable substitute index (either published or compiled or arranged by the Parties). 4.3 Payment of CBOV A) There will not be an invoice generated by SJCC for payment made pursuant to Section 4.1. B) Utilities agree to make an electronic funds transfer of CBOV due to SJCC including all applicable taxes, to SJCC's nominated account (to be nominated in writing by SJCC at least 60 days before the payment date) on or before the payment date described herein. Applicable taxes shall include any and all taxes (including without limitation gross income, gross receipts, value added, sales, use, occupation, franchise, personal property, stamp and other taxes), levies, imposts, duties, charges or withholdings of any nature whatsoever, together with any interest thereon (any of the foregoing fees, taxes and interest being for purposes hereof called "taxes") imposed by any sovereign political or governmental authority or taxing authority upon or in connection with SJCC's operation and with any activities and transactions under this Agreement (including reimbursements for SJCC Costs as described hereunder) excepting only taxes which are measured by net income (other than any such taxes measured by net income which are imposed in lieu of taxes measured by gross income and gross receipts). C) Utilities shall provide SJCC with documentation of the Inflation Index used to determine the payment amount with notification of the electronic funds transfer. 4.4 Payment of SJCC Costs A) Invoicing and Payment SJCC will invoice the Utilities for SJCC Costs. Invoices submitted by SJCC shall be due and payable by Utilities on the twenty-second (22nd) day of the month succeeding the month for which such invoice is submitted, or on the twelfth (12th) day after receipt of the invoice by Utilities, whichever date is later. Payment shall be made to SJCC by electronic funds transfer to such bank account as SJCC may from time to time designate. B) Disputed Invoices In case any portion of any invoice concerning SJCC Costs is disputed, the undisputed amount shall be paid when due; provided however, that Utilities may also pay the disputed portion of such invoice without thereby waiving their right to contest such disputed portion. Disputed invoices for SJCC Costs shall be referred initially to the Joint Committee for resolution. 4 C) Failure to Pay In the event Utilities fail to pay any amount due and not in bona fide dispute, SJCC shall be paid interest on all amounts owing under any invoice submitted hereunder which are not paid when due and payable, with said interest to be calculated at the Prime Rate as published in the Wall Street Journal for corporate loans posted by at least 75% of the nation's largest banks (or its equivalent) plus three percent (3%) but not in excess of the maximum rate of interest permitted by law and to be paid for the actual number of days elapsed since the invoice was due and payable. This right shall not be deemed an exclusive right or remedy. D) Audits SJCC will keep books, records and accounts necessary to show all information required for purposes of this Section 4.4. Upon Utilities' request, SJCC shall supply Utilities, by report and/or with actual source documents, the information reasonably necessary to verify any invoice for SJCC Costs issued pursuant to this Agreement; provided, however, that SJCC shall not be required to disclose information which in the opinion of SJCC is of a confidential nature due to the relationship of such information to SJCC's existing or contemplated operations. In the event Utilities and SJCC are unable to agree that the invoice is calculated correctly, a verification of such invoice shall be prepared and certified by a nationally recognized firm of certified public accountants, to be selected by Utilities from a list of three (3) such firms submitted by SJCC, such verification to set forth all data reasonably necessary to verify that the invoice is calculated correctly. The findings of said verification shall be accepted by both Utilities and SJCC as final and binding with respect to that invoice. The accounting firm selected for any such verification shall be bound not to disclose and shall treat as confidential any and all proprietary information of SJCC furnished to or examined by such firm in connection with such audit. It is understood that such verification shall not provide Utilities with nor entitle Utilities access to SJCC's books or records. If any such verification discloses that a calculation error has occurred and that, as a result thereof, an amount is due to one or the other party, such amount shall promptly be paid to whom it is owed; provided, however, if there is a dispute relating to the validity of a charge or adequacy of a payment either party may submit such dispute to the Joint Committee. All expenses of any such requested verification shall be paid by Utilities. Invoices which are not contested by either party within twenty-four (24) months from the date of the Invoice shall be deemed to be correct and will not thereafter be subject to verification. Section 5 - CSA Termination --------------------------- 5.1 CSA Termination Upon receipt of the CBOV payment by SJCC as adjusted and in consideration of the terms and conditions set forth in this Agreement, the CSA and the associated Guarantee by BHP Minerals International Inc. are terminated and all obligations under the CSA are satisfied. 5 Section 6 - SJCC Obligations ---------------------------- 6.1 SJCC Obligations SJCC shall use reasonable efforts consistent with law to minimize claims for costs referenced in Section 1.3(A) and to manage costs referenced in Section 1.3(C). Section 7 - Dispute Resolution ------------------------------ 7.1 Matters To Be Arbitrated; Notice of Claims and Defenses; Party Arbitrator Designation Either party may demand final and binding arbitration of any dispute, claim or controversy arising out of or relating to this Agreement, performance or actions pursuant to this Agreement, or concerning the interpretation of this Agreement (whether such matters sound in contract, tort or otherwise and including without limitation repudiation, illegality, and/or fraud in the inducement) by giving written notice to the other party of all claims it desires to submit to arbitration; provided, however, that matters within the authority of the Joint Committee must be presented first to that committee for consideration. Disputes regarding the payment of CBOV shall be immediately subject to arbitration in accordance with this section. The notice shall include: (a) the demanding party's designation of a party arbitrator; and (b) a detailed statement of the facts and theories supporting the claims. The party on whom the arbitration demand is served shall have thirty days from receipt of the notice to respond in writing to the demand and to submit any additional claims it wishes to submit to arbitration at the same time. The response also shall include: (a) the designation of the party arbitrator for that party; and (b) a detailed statement of the facts and theories supporting the claims and/or defenses asserted. The party originally demanding arbitration shall reply in writing to any additional claims submitted within ten days from the receipt of response. 7.2 Arbitrators; Selection of Neutral Arbitrator Any party who fails to designate timely its party arbitrator shall forfeit its right to designate an arbitrator. If only one arbitrator is timely designated, that single arbitrator shall hear the dispute. If two arbitrators are timely designated, those arbitrators shall, within thirty days, either agree on the appointment of a third, disinterested arbitrator knowledgeable as to the subject matter involved in the arbitration or petition the Chief Judge of the United States District Court for the District of New Mexico for the appointment of a third arbitrator. The parties shall be equally liable for the reasonable fees and expenses of the neutral arbitrator hearing the dispute. The parties shall be responsible for the fees and expenses of their respective party-appointed arbitrator. 6 7.3 Arbitration Hearings, Procedures and Timing All reasonable efforts will be made to hold a hearing on the claims submitted within sixty days after the appointment of the last arbitrator. In conducting the hearing, the arbitrators are directed, where feasible and where not inconsistent with the provisions of this paragraph, to adhere to the then-existing American Arbitration Association procedures and rules relating to commercial disputes. Unless otherwise agreed by the parties, the hearing shall be held in Farmington, New Mexico. 7.4 Choice of Law The arbitrators shall apply the laws of the State of New Mexico. 7.5 Award and Enforcement The decision or award of the arbitrators shall be given in writing within thirty days after the conclusion of the hearing. The arbitrators are authorized to award money damages, injunctive and declaratory relief and/or specific performance, if such relief in their opinion is appropriate. In any arbitration, each party shall bear its own costs, expenses, and attorneys' fees. The arbitrators do not have authority to award costs, expenses, or attorneys' fees to the prevailing party. The award or decision of the arbitrators shall be subject to review or enforcement in accordance with the New Mexico Uniform Arbitration Act, NMSA 1978 ss.ss. 44-7-1 et seq. Any party shall be entitled to recover reasonable attorneys' fees and costs incurred in enforcing any arbitration award or decision made pursuant to the arbitration provisions of this Agreement. 7.6 Performance Pending Arbitration Decision During the arbitration, unless otherwise ordered by the arbitrators, the parties agree to continued performance under this Agreement. 7.7 Definition of "Parties" for this Section For purposes of this Section 7, the Utilities shall be considered a single party. Specifically, and by example, the Utilities must act collectively to select their party arbitrator under Section 7.2 "Arbitrators; Selection of Neutral Arbitrator". Section 8 - Joint Committee --------------------------- 8.1 Purpose The intent of the Parties in providing for a Joint Committee is to establish an orderly and continuing means of dealing with matters that may arise from time to time in carrying out the provisions of this Agreement. The Joint Committee shall have four (4) members. 8.2 Designation During the term of this Agreement, SJCC will, by notice to Utilities, designate two (2) individuals as its representatives on the Joint Committee, and Utilities will, by notice to SJCC, designate two (2) individuals as their representatives on the Joint Committee; and each such representative shall be authorized by the party(ies) by whom he is 7 designated to act on its (their) behalf with respect to matters herein specified to be responsibilities of the Joint Committee. A representative may not delegate his responsibilities to others, but Utilities, or SJCC, may designate an alternate to act when said representative is unavailable. Either Utilities, or SJCC, by notice to the other, may change the designation of its (their) representatives. 8.3 Authority The Joint Committee shall have authority and responsibility to address disputes arising from or related to this Agreement other than disputes regarding the payment of CBOV. The Joint Committee shall not have any authority with respect to disputes regarding the payment of CBOV and such disputes shall be immediately subject to arbitration. 8.4 Decisions Decisions by the Joint Committee shall require the unanimous approval of all representatives of the Joint Committee and shall be evidenced by the signatures of all said representatives. 8.5 Relationship to Arbitration In case agreement should not be reached among the representatives of the Joint Committee as to any of the matters referred to in Section 8.3 "Authority" as responsibilities of the Joint Committee, such matters shall be forthwith submitted to and determined by arbitration as provided for in Section 7 "Dispute Resolution". Section 9 - General Provisions ------------------------------ 9.1 Confidentiality The terms and conditions, including those dealing with compensation, set forth in this Agreement are considered by Utilities and SJCC to be confidential and proprietary information and none of the parties shall disclose any such information to any third party other than the attorneys, auditors and agents of Utilities, other owners of the San Juan Station, and SJCC, without the advance written consent of the other parties; provided however, disclosure may be made without advance consent where, in the opinion of counsel, such disclosure may be required by order of court or regulatory agency, law or regulation or in connection with judicial or administrative proceedings involving a party hereto, in which event the party to make such disclosure shall advise the other parties in advance as soon as possible and cooperate to the maximum extent practicable to minimize the disclosure of any such information, including, where practicable, deletion of portions of this Agreement relating to compensation, including, Section 4 "SJCC Compensation". 8 Utilities shall maintain with the owners of the San Juan Station other than the Utilities written confidentiality agreements that are acceptable to SJCC prior to the disclosure of the terms of this Agreement. 9.2 Joint and Several The Utilities' duties and obligations under this Agreement shall be joint and several. 9.3 Entire Agreement This Agreement supersedes all prior agreements and representations between the Parties, whether written or oral, with respect to the subject matter of this Agreement and is intended as a complete and exclusive statement of the terms of the agreement between the Parties with respect to the subject matter. Except as specifically set forth in this Agreement, no representations have been made to induce any of the Parties to enter into this Agreement. 9.4 Successors and Assigns This Agreement and all of the rights and obligations of the Parties described shall extend to and be binding upon, and shall inure to the benefit of, the respective successors and assigns of the respective Parties. 9.5 Construction The terms and conditions of this Agreement are the result of negotiation and drafting on an equal footing by the Parties and their legal counsel. This Agreement shall be construed evenhandedly and without favor or predisposition to any party. 9.6 Waiver of Consequential Damages. SJCC and the Utilities waive any recovery of consequential damages related to the breach of this Agreement. 9.7 Notices A) Any notice, demand or request provided for in this Agreement, or given or made in connection with this Agreement shall be in writing, signed by an officer of the party giving such notice and shall be deemed to be properly and sufficiently given or made if sent by registered or certified mail, and if to SJCC, addressed as follows: San Juan Coal Company 300 West Arrington, Suite 200 Farmington, NM 87401 Attention: President with a copy addressed as follows: San Juan Coal Company Post Office Box 155 Fruitland, NM 87416 Attention: San Juan Mine Manager 9 and if to Utilities, addressed as follows: Public Service Company of New Mexico Alvarado Square Albuquerque, NM 87158 Attention: Corporate Secretary and Tucson Electric Power Company Post Office Box 711 Tucson, AZ 85702 Attention: Secretary B) Any party hereto may change its address for notice by so advising the other Parties hereto in accordance with the provisions of this Section 9.7. Any notice given in accordance with the provisions of this Section 9.7 shall be deemed effectively given as of the date of its deposit with the United States Postal Service. 10 Section 10 - Signatures ----------------------- IN WITNESS WHEREOF, SJCC, and the Utilities, by their duly authorized representatives, have entered into this Agreement. PUBLIC SERVICE COMPANY OF NEW MEXICO By: /s/ Patrick J. Goodman 8/29/01 ---------------------------------------- ------- Patrick J. Goodman, Vice President Date TUCSON ELECTRIC POWER COMPANY By: /s/ Kevin Larson 8/31/01 ------------------------------------------------- ------- Kevin Larson, Vice President Date SAN JUAN COAL COMPANY By: /s/ John W. Grubb 8/29/01 ---------------------------------------- ------- John W. Grubb, President Date 11 EX-10 7 exh1085.txt EXHIBIT 10.85 Exhibit No. 10.85 [*] indicates that the confidential portion has been omitted from this filed exhibit and filed separately with the Securities and Exchange Commission. Underground Coal Sales Agreement -------------------------------- Among San Juan Coal Company And Public Service Company of New Mexico And Tucson Electric Power Company Table of Contents Section 0 - Parties and Recitals.............................................1 Section 1 - Definitions......................................................2 1.1 Alternate Coal...................................................2 1.2 Cimarron Coal Assignment.........................................2 1.3 Coal Leases......................................................2 1.4 Fruitland Coal Sublease..........................................2 1.5 Guarantee........................................................2 1.6 Mineable Coal....................................................2 1.7 Non-SJCC Coal....................................................3 1.8 Processed Coal...................................................3 1.9 Remnant Coal.....................................................3 1.10 Reserve of Coal..................................................3 1.11 SJCC Site Area...................................................3 1.12 San Juan Station.................................................4 1.13 Ton..............................................................4 1.14 Ute ROW..........................................................4 1.15 Definitions of Other Terms.......................................4 Section 2 - Obligations of the Parties and Term of Agreement.................6 2.1 Obligations of SJCC..............................................6 2.2 Obligations of Utilities.........................................6 2.3 Term.............................................................7 2.4 Conditions Precedent.............................................7 2.5 Extension........................................................7 2.6 Representations and Warranties...................................7 Section 3 - Coal Supply......................................................8 3.1 Ownership of Coal................................................8 3.2 Alternate Coal...................................................8 Section 4 - Delivery of Coal.................................................9 4.1 Delivery Points..................................................9 4.2 Delivery Rates...................................................9 4.3 Utilities' Coal Storage.........................................10 Section 5 - Coal Specifications and Weighing, Sampling, and Analysis........11 5.1 Coal Size.......................................................11 5.2 Coal Quality....................................................11 5.3 Utilities' Right of Rejection...................................11 5.4 Weighing and Analysis Facilities and Methods....................12 i Section 6 - Coal Leases, Land, and Land Rights..............................13 6.1 Dedicated Reserves..............................................13 6.2 SJCC's Facilities...............................................13 6.3 Utilities' Rights Vis-a-Vis the SJCC Site Area..................13 6.4 Waste Disposal Area.............................................14 6.5 Compliance with Leases and Other Instruments....................14 6.6 Restrictions on SJCC............................................15 6.7 Site Area Lease Management......................................15 Section 7 - Operations......................................................17 7.1 Mining Plans and Methods........................................17 7.2 Processing Methods..............................................17 7.3 Reclamation Activities..........................................17 Section 8 - SJCC Compensation...............................................19 8.1 Compensation Components.........................................19 8.2 Mining and Reclamation Component................................19 8.3 Coal Processing Component.......................................24 8.4 Non-SJCC Coal and Alternate Coal Costs..........................27 8.5 Other Costs.....................................................28 8.6 Inflation - Deflation Adjustment................................29 8.7 Invoicing and Settlement........................................30 Section 9 - Coordinating Committee..........................................33 9.1 Purpose.........................................................33 9.2 Designation.....................................................33 9.3 Procedures and Practices........................................33 9.4 Coordinating Committee Decisions................................34 9.5 Relationship to Joint Committee and Arbitration.................34 Section 10 - Joint Committee................................................35 10.1 Purpose.........................................................35 10.2 Designation.....................................................35 10.3 Authority.......................................................35 10.4 Decisions by the Joint Committee................................36 10.5 Relationship to Arbitration.....................................37 Section 11 - Dispute Resolution.............................................38 11.1 Matters To Be Arbitrated; Notice of Claims and Defenses; Party Arbitrator Designation....................................38 11.2 Arbitrators; Selection of Neutral Arbitrator....................38 11.3 Arbitration Hearings, Procedures and Timing.....................38 11.4 Choice of Law...................................................38 11.5 Award and Enforcement...........................................39 11.6 Performance Pending Arbitration Decision........................39 11.7 Definition of "Party" for this Section..........................39 ii Section 12 - Non-Normal Conditions, Right to Cure, Termination and Expiration.................................................40 12.1 Utilities' Right to Mine........................................40 12.2 Uncontrollable Forces...........................................40 12.3 Non-Normal Conditions, Right to Cure, and Offers of Non-SJCC Coal................................................40 12.4 Material Default................................................43 12.5 Termination.....................................................44 12.6 Expiration......................................................46 Section 13 - Indemnity......................................................48 13.1 Indemnity.......................................................48 Section 14 - General Provisions.............................................49 14.1 Compliance with Applicable Laws.................................49 14.2 Labor Force.....................................................49 14.3 Confidentiality / Non-disclosure................................51 14.4 The Utilities' Duties and Obligations Shall be Joint and Several......................................51 14.5 Permits and Approvals...........................................51 14.6 Waivers.........................................................51 14.7 Insurance.......................................................51 14.8 Notices.........................................................52 14.9 Choice of Law...................................................53 14.10 Assignment......................................................53 14.11 Successors and Assigns..........................................54 14.12 Authorizations..................................................54 14.13 Amendments......................................................54 14.14 Construction....................................................54 14.15 Entire Agreement................................................54 14.16 Waiver of Consequential Damages.................................55 14.17 Severability....................................................55 14.18 Survival of Provisions..........................................55 Section 15 - Signatures.....................................................56 Exhibits and Attachment Attachment "1" Guarantee Exhibit "A" Coal Leases Exhibit "B" Delivery Points Exhibit "C" Mining Plans and Methods Exhibit "D" Delivery Rates Exhibit "E" SJCC Site Area Exhibit "F" Operating Costs Exhibit "G" Tax Calculations Exhibit "H" San Juan Station Minimum Deliveries 2003-2017 iii Section 0 - Parties and Recitals -------------------------------- THIS AGREEMENT ("Agreement") is dated August 31, 2001, to become effective on January 1, 2003, as provided herein, between SAN JUAN COAL COMPANY, a Delaware corporation ("SJCC"), and PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation, and TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (herein collectively referred to as "Utilities"), (with SJCC and Utilities herein sometimes collectively referred to as "Parties"). WHEREAS, SJCC has acquired coal leases and surface rights known as the Coal Leases which are more particularly described in Exhibit "A" "Coal Leases"; WHEREAS, Utilities own, in part, a coal-burning power plant in the vicinity of the Coal Leases (hereinafter referred to as the "San Juan Station"); WHEREAS, the San Juan Station currently consists of four generating units (as hereinafter defined); WHEREAS, Utilities desire to have SJCC sell Utilities coal that has been mined from an underground coal mine (the "UG Mine") on the Coal Leases and delivered to the delivery point(s) shown on Exhibit "B" "Delivery Points" and SJCC is willing to undertake such obligation upon the terms and conditions hereinafter set forth, and; WHEREAS, the purpose of this Agreement is to set forth the agreement between the Parties relating to the supply of coal by SJCC to the San Juan Station. NOW, THEREFORE, in consideration of the terms, covenants and agreements contained in this Agreement, Utilities jointly and severally agree with SJCC as follows: 1 Section 1 - Definitions ----------------------- When used in this Agreement, the terms defined in this Section 1 shall have the following meanings. 1.1 Alternate Coal "Alternate Coal" shall mean coal other than Mineable Coal or Non-SJCC Coal that is acquired pursuant to Section 3.2 "Alternate Coal" that meets the following criteria: A) It has been approved by the Joint Committee for processing and delivery or inclusion in the Reserve of Coal; B) It is reasonable to expect that it can be processed to meet the Coal Quality and Coal Size requirements described in Section 5 "Coal Specifications and Weighing, Sampling, and Analysis"; C) It has been severed from sources other than the Coal Leases; and, D) It may be intended for short-term supply. 1.2 Cimarron Coal Assignment "Cimarron Coal Assignment" shall mean that particular Assignment Agreement, dated October 30, 1979, originally between Cimarron Coal Company and Western Coal Company and assigned to SJCC, as amended and modified. 1.3 Coal Leases "Coal Leases" shall refer to those certain coal leases (some whole coal leases and some portions of other coal leases) which are described in Exhibit "A" "Coal Leases". 1.4 Fruitland Coal Sublease "Fruitland Coal Sublease" shall mean that particular Sublease dated August 18, 1980, between Western Coal Company as Sublessor and Utah International Inc. as Sublessee. 1.5 Guarantee "Guarantee" shall mean the Guarantee, of even date herewith, made by BHP Minerals International Inc. and guaranteeing to Utilities SJCC's performance of its obligations hereunder. 1.6 Mineable Coal "Mineable Coal" shall mean that coal which is Remnant Coal or meets the following four criteria: A) Is within the Coal Leases (as herein defined); B) Can reasonably be expected to be mined utilizing the Mining Plans and Methods herein defined; C) Can reasonably be expected to meet the heating value specifications described in Section 5.2 "Coal Quality" (unless the Utilities' Coordinating Committee representative agrees that a lower heating value is acceptable); and, 2 D) Is contained in the Number 8 coal seam referenced in Exhibit "C" "Mining Plans and Methods" and is at least the thickness of the minimum operating height of the longwall shearer, excluding local anomalies. 1.7 Non-SJCC Coal "Non-SJCC Coal" shall mean coal that is offered to Utilities pursuant to Section 12.3 "Non-Normal Conditions, Right to Cure, and Offers of Non-SJCC Coal" and meets the following criteria: A) It has been approved by the Joint Committee for processing and delivery or inclusion in the Reserve of Coal; B) It is reasonable to expect that it can be processed to meet the Coal Quality and Coal Size requirements described in Section 5 "Coal Specifications and Weighing, Sampling, and Analysis"; C) It has been severed from sources other than the Coal Leases; and, D) It is intended for short-term supply. 1.8 Processed Coal "Processed Coal" shall mean coal that has been processed according to Section 7.2 "Processing Methods". 1.9 Remnant Coal "Remnant Coal" shall mean coal uncovered by SJCC at its discretion utilizing mining methods other than the Mining Plans and Methods described herein from coal leases on the SJCC Site Area before January 1, 2004, and that was not bought out by the Utilities pursuant to the Coal Sales Agreement Buy Out Agreement of even date herewith. 1.10 Reserve of Coal "Reserve of Coal" shall mean all Mineable Coal, Non-SJCC Coal, and Alternate Coal on the SJCC Site Area that is mined coal in storage or un-mined coal from which the overburden has been removed. 1.11 SJCC Site Area "SJCC Site Area" is identified in Exhibit "E" "SJCC Site Area" and includes the following: A) Coal Leases as described in Exhibit "A" "Coal Leases". B) San Juan Mine and facilities including coal receiving, handling, delivery, and crushing facilities, coal weighing and sampling facilities, service road, maintenance and office buildings, fencing and auxiliary facilities. C) La Plata Mine and facilities including coal weighing facilities, service road, maintenance and office buildings, fencing and auxiliary facilities. D) Transportation Corridor facilities including the haul road, water system, fencing and auxiliary facilities. 3 1.12 San Juan Station That certain coal-fired power plant currently operated by Public Service Company of New Mexico and owned, in part, by Utilities, presently consisting of four generating units. The First Unit has a net rated capacity of approximately 327,000 kW. The Second Unit has a net rated capacity of approximately 316,000 kW. The Third Unit has a net rated capacity of approximately 497,000 kW. The Fourth Unit has a net rated capacity of approximately 507,000 kW. 1.13 Ton Equal to 2,000 pounds and the same as a short ton when used herein. 1.14 Ute ROW "Ute ROW" shall mean that particular right of way agreement dated July 29, 1981, between Western Coal Company (which interest has been assigned to SJCC) and the Ute Mountain Ute Tribe of the Ute Mountain Ute Reservation, as amended. 1.15 Definitions of Other Terms Definitions of terms used predominantly in Section 8, appear in Section 8.2(F) "Definitions". Definitions of other terms appear elsewhere throughout this Agreement. These include: A) "Administration Element", defined in Section 8.2(D); B) "Agreement", defined in Section 0; C) "Annual CIE Amount", defined in Section 8.2(E); D) "Annual Processing Tons", defined in Section 8.3(A)(5); E) "Base CIE Amount", defined in Section 8.2; F) "Base CIEOriginal", defined in Section 8.2(A)(1); G) "Base CIEtax adj.", defined in Section 8.2(A)(1); H) "Base CIEtrue up adj.", defined in Section 8.2(A)(1); I) "BMT", defined in Section 8.2(A)(3); J) "CIE Reconciliation Amount", defined in Section 8.2; K) "Coal Costs", defined in Section 8.1; L) "Cure Plan", defined in Section 12.3(E)(1); M) "Deflator", defined in Section 8.6(A); N) "Delivery Points", defined in Section 4.1(A); O) "Depletion-eligible Reimbursable SJCC Coal Processing Costs", defined in Section 8.3(B)(2); P) "Depletion-ineligible Reimbursable SJCC Coal Processing Costs" defined in Section 8.3(B)(3); 4 Q) "Eligible Processing Administration Element", defined in Section 8.3(C)(1); R) "Emergency Situation", defined in Section 12.1(A); S) "IMT", defined in Section 8.2(B)(3); T) "Incremental CIE Amount", defined in Section 8.2; U) "Index", defined in Section 8.6(A); V) "Inferior Coal", defined in Section 5.3; W) "Inflation Index", defined in Section 8.6(A); X) "Material Default Conditions", defined in Section 12.3; Y) "Monthly Eligible Processing Tons", defined in Section 8.3(A)(5); Z) "Monthly Non-Eligible Processing Tons", defined in Section 8.3(A)(5); AA) "Monthly Processing Tons", defined in Section 8.3(A)(5); BB) "NBMT", defined in Section 8.2(A)(3); CC) "NIMT", defined in Section 8.2(B)(3); DD) "Non-Eligible Processing Administration Element", defined in Section 8.3(C)(2); EE) "Processing Administration Element", defined in Section 8.3(C); FF) "Processing CIE Amount", defined in Section 8.3; GG) "Processing CIE Reconciliation Amount", defined in Section 8.3; HH) "Processing CIEEligible", defined in Section 8.3(A)(2); II) "Processing CIEEligible-Adj", defined in Section 8.3(A)(3); JJ) "Processing CIEEligible-Org", defined in Section 8.3(A)(1); KK) "Processing CIENon-eligible", defined in Section 8.3(A)(2); LL) "Processing CIENon-elg-Adj.", defined in Section 8.3(A)(3); MM) "Processing CIENon-elg-Org", defined in Section 8.3(A)(2); NN) "Reimbursable Operating Costs", defined in Section 8.2; OO) "Reimbursable Processing Costs", defined in Section 8.3; PP) "Uncontrollable Forces" is defined in Section 12.2; QQ) "Utilities' Coal Storage", defined in Section 4.2(B); and, RR) "Waste", defined in Section 6.4. 5 Section 2 - Obligations of the Parties and Term of Agreement ------------------------------------------------------------ 2.1 Obligations of SJCC Pursuant to the provisions of this Agreement, the obligations of SJCC include: A) To produce Mineable Coal from the Coal Leases, B) To process and crush Mineable Coal, Non-SJCC Coal and/or Alternate Coal in the facilities of SJCC to a size and quality specified in Sections 5.1 "Coal Size" and Section 5.2 "Coal Quality", C) To deliver and sell, at the request of Utilities, Processed Coal to Utilities at the Delivery Point(s) as defined in Section 4.1 "Delivery Points" and at the Delivery Rates as defined in Section 4.2 "Delivery Rates", and, D) To perform reclamation activities on the SJCC Site Area. SJCC recognizes that Utilities are relying on SJCC to perform all of its obligations hereunder in order for Utilities to operate the San Juan Station and that Utilities' access to other sources of fuel for the San Juan Station is limited. SJCC, therefore, agrees to accept full responsibility for delivery of Processed Coal to the San Juan Station in accordance with Section 4 "Delivery of Coal". SJCC further acknowledges that Utilities are relying on the Mining Plans and Methods to recover coal and that SJCC has designed its Mining Plans and Methods to: 1) Maximize recovery of Mineable Coal, subject to good minerlike practices and to the terms of the Coal Leases; and 2) Efficiently and economically mine and deliver coal to Utilities. SJCC will exercise good faith efforts to achieve two (2) consecutive months of Mineable Coal production equivalent to 550,000 Tons per month from the UG Mine on or before December 31, 2002. 2.2 Obligations of Utilities Pursuant to the provisions of this Agreement, the obligations of Utilities include: A) To purchase all coal required for the operation of the San Juan Station from SJCC subject to the provisions of and consistent with the terms of this Agreement; provided however, that Utilities may during periods, if any, when SJCC may be unable, whether due to Uncontrollable Forces or otherwise, to furnish coal to the Delivery Point(s), obtain coal from other sources to maintain and protect full capacity operation of the San Juan Station, B) To compensate SJCC for all reclamation activity, including ongoing and post term reclamation of the SJCC Site Area pursuant to Section 7.3 "Reclamation Activities"; and C) To make payments as specified in Section 8 "SJCC Compensation". 6 2.3 Term This Agreement shall expire December 31, 2017, unless such term is extended by mutual written agreement of the Parties. 2.4 Conditions Precedent The conditions precedent to this Agreement becoming effective on January 1, 2003, are: A) The final approval of this Agreement by the San Juan Fuels Committee pursuant to the requirements of the San Juan Project Participation Agreement dated as of October 27, 1999, to be obtained no later than September 28, 2001, and written notification of such approval to SJCC by the Utilities. B) The final approval of the Capital True Up Agreement by the San Juan Fuels Committee pursuant to the requirements of the San Juan Project Participation Agreement dated as of October 27, 1999, to be obtained no later than September 28, 2001, and written notification of such approval to SJCC by the Utilities. C) Execution of the Guarantee by the Guarantor in the form attached to this Agreement and incorporated herein as Attachment 1, to be obtained no later than September 28, 2001, and provided to Utilities by SJCC. 2.5 Extension Utilities may, by written notice to SJCC given on or before December 31, 2007, indicate their intent to extend the term of this Agreement for an additional period of not less than five (5) years. If such notice is given, SJCC and Utilities shall negotiate diligently and in good faith to reach agreement on such extension. If the Parties have not agreed to an extension prior to the expiration of the initial term of this Agreement, or such other date as they may establish, this Agreement shall terminate as provided for herein. 2.6 Representations and Warranties As of the execution of this Agreement and subject to satisfaction of the applicable conditions precedent described in this Agreement, each party warrants and represents that: A) It is a corporation duly organized and in good standing in its state of incorporation and is qualified to do business and is in good standing in those states where necessary in order to carry out the purposes of this Agreement; B) It has the capacity to enter into and perform this Agreement and all transactions contemplated in this Agreement, and that all corporate actions required to authorize it to enter into and perform this Agreement have been taken properly; and C) This Agreement has been duly executed and delivered by it and is valid and binding upon it in accordance with its terms. 7 Section 3 - Coal Supply ----------------------- 3.1 Ownership of Coal All coal contained in the Coal Leases, Reserve of Coal, and Remnant Coal shall at all times be and remain the property of SJCC (subject in the case of coal contained in the Fruitland Coal Sublease to certain security interests therein retained by other parties). Once said coal is delivered to Utilities pursuant to Section 4.1 "Delivery Points", title thereto shall pass to Utilities free and clear of all claims, liens and encumbrances. 3.2 Alternate Coal A) In the event that during the Term of this Agreement 1) the Joint Committee concludes that SJCC may be able to deliver Alternate Coal to Utilities with an acquisition cost that is less than the Reimbursable Operating Costs as defined in Section 8.2(C) "Reimbursable Operating Costs" for Mineable Coal or, 2) if the Parties agree that Alternate Coal should otherwise be substituted for Mineable Coal, then, subject to final Joint Committee approval, SJCC shall use its best efforts to acquire Alternate Coal for delivery under this Agreement and to substitute such Alternate Coal for that amount of Mineable Coal otherwise deliverable hereunder which the Joint Committee or the Parties (as the case may be) have agreed upon; provided that, such Alternate Coal shall be priced as described in Section 8 "SJCC Compensation" including a Base CIE or an Incremental CIE, as applicable, and full reimbursement of acquisition costs, and any Operating Costs as defined in Exhibit "F" "Operating Costs" adjusted for depletion if appropriate, and shall meet the specifications identified in Section 5 "Coal Specifications and Weighing, Sampling, and Analysis" or such specifications as shall be agreed upon by Utilities. 8 Section 4 - Delivery of Coal ---------------------------- 4.1 Delivery Points A) SJCC will deliver Processed Coal to delivery point(s) on the San Juan Station situated in the location(s) shown as "Delivery Points" on Exhibit "B" "Delivery Points". B) Processed Coal shall be deemed delivered when it is deposited in one of the Utilities' coal surge piles at the Delivery Point(s), and title shall pass to Utilities at the point of entry into said coal surge piles; thereafter, Utilities shall be responsible for all such delivered coal. C) Matters of mutual interest in connection with the coal handling facilities, and specific methods and locations of delivery are hereby made a responsibility of the Coordinating Committee, such responsibility to be carried out as provided for in Section 9 "Coordinating Committee". 4.2 Delivery Rates A) SJCC shall deliver coal to the Utilities at the Delivery Point(s) pursuant to Sections 4.2(B) and 4.2(C) hereof, such deliveries, to the extent practicable, to be at approximate uniform rates during the delivery periods and in annual amounts as shown in Exhibit "D" "Delivery Rates" as may be adjusted; provided, however, that in no event shall SJCC at any time be obligated to mine coal in a manner inconsistent with the Mining Plans and Methods. The annual amounts shown in Exhibit "D" "Delivery Rates" will be adjusted as provided for in Sections 4.2(B) and 4.2(C); provided, however, that such amounts may not be adjusted upward to exceed 130,000 Tons per week or 6,760,000 Tons per year, unless otherwise agreed to by the Joint Committee. B) During the term of this Agreement, Utilities will provide SJCC annually, on or about September 1st, a schedule of monthly and annual planned coal consumption for operation of the San Juan Station and for Utilities' Coal Storage (defined in Section 4.3 "Utilities' Coal Storage"). This annual consumption forecast provided by the Utilities will supercede the tonnage specified in Exhibit "D" "Delivery Rates" for that year, if the annual schedule is consistent with the provisions of Section 4.2(A). Utilities will notify SJCC promptly and, if possible, in advance, of any changes in such scheduled amounts due to outage of generating units or other causes. In the event of an increase in said scheduled amounts upon less than eight (8) weeks' notice, SJCC agrees to use its best efforts to meet such increase at the date scheduled, and in any event, subject to the limitations of Section 4.2(A), it will meet such increase within eight (8) weeks of notice thereof. C) The Joint Committee may, in accordance with the provisions of Section 10 "Joint Committee", adjust either upward or downward the tonnage specified in this Section 4.2 "Delivery Rates", provided such adjustment is not in conflict with any other provision of this Agreement and does not materially impact the Mining Plans and Methods. 9 4.3 Utilities' Coal Storage Utilities intend to maintain at the San Juan Station site a storage pile of Processed Coal ("Utilities' Coal Storage"). The amount of such storage will be determined by Utilities from time to time in the future and may be varied from time to time. Should any part of this coal storage pile be depleted or should the size of the pile be increased as provided for herein, subject to the limitations on SJCC's delivery obligations contained herein, SJCC agrees to deliver replacement or additional coal at the earliest practicable time in order that the amount of coal will reach the required level, as determined by the Utilities and consistent with this Agreement. Delivery of Processed Coal for Utilities' Coal Storage will not be required if such delivery would trigger Non-Normal Conditions. 10 Section 5 - Coal Specifications and Weighing, Sampling, and Analysis -------------------------------------------------------------------- 5.1 Coal Size Crusher settings will be established by the Coordinating Committee. No selected sizes shall be removed from the Processed Coal. 5.2 Coal Quality Coal to be delivered pursuant to this Agreement shall have been mined with diligence and care, and in accordance with good minerlike practice, to minimize contamination of coal by material extraneous to the coal seam being mined. Subject to the provisions of this Section 5 and Section 12 "Non-Normal Conditions, Right to Cure, Termination, and Expiration", SJCC will deliver to Utilities coal which shall have an average heating value of not less than 9,000 BTU per pound, as received, averaged over any 24-hour period when SJCC is delivering coal, unless a variance from such standard shall have previously been agreed upon by the Coordinating Committee in accordance with Section 9 "Coordinating Committee". Such 24-hour period shall be from midnight to midnight, unless the Coordinating Committee shall agree otherwise in accordance with Section 9 "Coordinating Committee" 5.3 Utilities' Right of Rejection Subject to the provisions of Section 12 "Non-Normal Conditions, Right to Cure, Termination and Expiration", in the event that coal delivered during any 24-hour period referred to in Section 5.2 "Coal Quality" shall have an average heating value of less than 9,000 BTU per pound, as received, ("Inferior Coal") and such delivery shall not have been authorized by prior agreement of the Utilities' Coordinating Committee Representative or the Joint Committee, then SJCC shall give the Utilities prompt notice of the delivery of such Inferior Coal, and the Utilities may then choose either one of the two options described below and promptly notify SJCC of such decision. Such election shall constitute an exclusive remedy for delivery of Inferior Coal, unless a dispute arises under Section 5.3(A) or Section 5.3(B), in which case either party may demand arbitration pursuant to Section 11 "Dispute Resolution". A) If the Utilities choose to accept the Inferior Coal, they may request a price reduction for such Inferior Coal. Such price reduction shall be determined by the following formula and credited against the Interim Invoice and the UG-CSA Invoice for the month that the Inferior Coal was delivered: Price Reduction = 24-hour Tons X price X grade factor Where: "24-hour Tons" is equal to the Tons of coal sold in the 24-hour period in which the Inferior Coal was delivered; "price" is equal to the UG-CSA Invoice price for the month in which the Inferior Coal was delivered; and, 11 "grade factor" is equal to the [the contract grade minus the grade of the Inferior Coal for the 24-hour period] divided by the contract grade. The contract grade is 9,000 BTU per pound or as otherwise agreed by the Coordinating Committee. B) If the Utilities choose to reject such Inferior Coal, the Coordinating Committee shall develop a plan to mitigate the situation. SJCC at its own expense will use reasonable efforts to implement the mitigation measures. 5.4 Weighing and Analysis Facilities and Methods Facilities for the weighing, sampling and analysis of coal shall be owned, operated and maintained by SJCC. A) Methods shall be established for determining the weight and BTU content of coal delivered, in accordance with accepted good practice and applicable portions of the ASTM standards, or such other procedures as the Coordinating Committee may determine with due regard for overall economy in investment and in operation, including splitting of samples and bias testing by an independent commercial firm qualified to conduct such testing. B) Utilities may at any time observe the weighing, sampling and analysis operations of SJCC as herein provided and report thereon to the Coordinating Committee. 12 Section 6 - Coal Leases, Land, and Land Rights ---------------------------------------------- 6.1 Dedicated Reserves The coal reserves contained within the Coal Leases are dedicated to production for the San Juan Station except as provided otherwise herein. Before SJCC acquires any coal leases contiguous with the Coal Leases, SJCC will offer to dedicate such coal leases to production for the San Juan Station. Upon approval (which approval shall not be withheld unreasonably) by the Joint Committee of the terms for incorporating such leases into this Agreement, those coal leases if acquired, will become dedicated to production for the San Juan Station except as provided otherwise herein. 6.2 SJCC's Facilities A) SJCC has, or will use its best efforts to further secure by January 1, 2003, right of use of the SJCC Site Area, either by right, deed, lease, or other instrument. B) It is understood that the boundaries of the SJCC Site Area that are adjacent to the San Juan Station may, with the consent of Utilities, be enlarged as SJCC's needs expand. Any such enlargement shall be a responsibility of the Joint Committee, to be carried out as provided for in Section 10 "Joint Committee". C) Utilities hereby agree that as among Utilities and SJCC and their respective successors and assigns, the coal mining, coal processing and mining reclamation equipment and related assets owned by SJCC and located on the San Juan Station site are and shall remain personal property of SJCC. Utilities agree to grant to any purchaser of such equipment and assets from SJCC such easements and rights-of-way as shall be necessary to enable such purchaser to enter upon the lands of Utilities to remove same. 6.3 Utilities' Rights Vis-a-Vis the SJCC Site Area A) In the event that Utilities-authorized persons wish to enter the SJCC Site Area, Utilities shall first give notice to the mine manager, or his representative, or follow Coordinating Committee guidelines in order to facilitate compliance with safety requirements. B) SJCC grants to Utilities such rights as SJCC may have to install, maintain and operate and the right to permit others, including but not limited to affiliated companies of the Utilities, to install, maintain and operate roads, railroads, overland conveyors, electric power-lines, water pipelines and other facilities over and upon the SJCC Site Area; provided, however, that such installation, maintenance and operation shall not interfere with SJCC's operations and obligations under this Agreement and provided further that such activity shall comply with applicable law and lease terms. 13 6.4 Waste Disposal Area In connection with the Waste Disposal Agreement dated July 27, 1992, as amended, SJCC will maintain, to the extent permitted by, and in compliance with, applicable laws, regulations and permits, suitable waste disposal areas within the SJCC Site Area. "Waste" shall be defined as material disposed of pursuant to the Waste Disposal Agreement. 6.5 Compliance with Leases and Other Instruments A) SJCC shall not perform any act or undertake any activity which would violate any covenant under any of the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal, Waste disposal, reclamation, and other activities of SJCC under this Agreement, and which could have the effect of causing forfeiture of SJCC's rights under said leases and other instruments, including nonpayment of rentals or royalties due under the provisions of such leases and instruments. B) In the event that any regulatory requirement shall impose upon SJCC an obligation to produce coal in an amount which cannot be produced using the Mining Plans and Methods, then the Joint Committee shall approve such changes to the Mining Plans and Methods as are reasonably required to enable SJCC to comply with such obligation and the Utilities' representatives on the Joint Committee shall not unreasonably withhold their approval of such changes. C) It is agreed that, in the event there is attached to SJCC's interest in the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal, Waste disposal, reclamation, and other activities of SJCC under this Agreement, a judgment lien against SJCC resulting from a final judgment issued by any court of competent jurisdiction, which judgment is not appealable to any court, or a lien created by statute, which statutory lien is not being contested by SJCC and which SJCC does not intend to contest, and legal procedure has been commenced for the sale of SJCC's interest in the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal, Waste disposal, reclamation, and other activities of SJCC under this Agreement, pursuant to such judgment, lien or statutory lien, Utilities, after giving SJCC written demand to pay such judgment or discharge such lien and SJCC having failed to do so within a reasonable time after such demand, shall have the right at their option to pay and discharge said judgment or lien prior to such sale or to redeem the Coal Leases or other 14 leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal, Waste disposal, reclamation, and other activities of SJCC under this Agreement, after such sale as provided by law, in which event all sums expended by Utilities to discharge said lien or to redeem said property, as provided by law, shall be payable by SJCC to Utilities upon demand. 6.6 Restrictions on SJCC A) Subject to Section 6.7 "Site Area Lease Management", SJCC shall not assign, transfer, convey, mortgage, encumber or otherwise dispose of interests or rights in the Coal Leases or other leases, rights of way grants and easements, or other agreements, licenses or permits required for the mining, processing, transportation, delivery and sale of coal, Waste disposal, reclamation, and other activities of SJCC under this Agreement, except as contemplated by Section 14.10 "Assignment", without the prior written consent of Utilities. SJCC may sell to parties other than Utilities, coal mined from the Coal Leases and any approved contiguous lease additions which is not required by SJCC to meet its obligations hereunder and SJCC shall have no liability to Utilities by reason of such sale; provided, however, that no said sale shall be made without the prior written consent of the Utilities' representatives on the Joint Committee. B) Notwithstanding the foregoing provisions of this Section 6.6, if for a period of thirty-six (36) consecutive months, Utilities shall be entirely excused pursuant to the provisions of Section 12.2 "Uncontrollable Forces" hereof from their obligation to accept deliveries of and to pay for coal from the Coal Leases, then SJCC shall attempt to sell coal from the Coal Leases to persons other than Utilities. Utilities agree that they will consent to such sales 1) if such sales will not, in Utilities' reasonable judgment, interfere with the provision of the then anticipated annual and total estimated fuel needs of the San Juan Station, but not to exceed the tonnage specified in Section 4.2 "Delivery Rates", through the remaining Term (unless otherwise agreed by the Parties), and 2) appropriate amendments are made to the components of compensation set forth in Section 8 "SJCC Compensation" to reflect the decreased tonnage of coal that will be delivered to Utilities from the Coal Leases. To the extent necessary to maintain the Coal Leases by production, SJCC may sell coal from the Coal Leases to persons other than Utilities during the thirty-six (36) month period. C) Except for incidental uses, SJCC will use underground facilities within the UG Mine solely to meet SJCC's obligations under this Agreement. 6.7 Site Area Lease Management SJCC shall have the responsibility and authority to manage all leases, rights of way grants and easements, or other agreements, licenses or permits for the SJCC Site Area. Management of the Coal Leases and other areas required for the mining, processing, transportation, delivery, Waste disposal, reclamation, and sale of coal pursuant to this Agreement is restricted pursuant to Section 6.6 "Restrictions on SJCC". 15 Section 7 - Operations ---------------------- 7.1 Mining Plans and Methods A) SJCC will mine and deliver coal in accordance with the mining methods set forth in Exhibit "C" "Mining Plans and Methods" incorporated herein by reference. To mine Remnant Coal, SJCC at its discretion may use mining methods other than those described in Exhibit "C" "Mining Plans and Methods". SJCC agrees that it will not significantly amend, revise or modify the Mining Plans and Methods, unless necessary to comply with applicable statutes, regulations and rulings, without first gaining Joint Committee approval if the effect of such amendment, revision or modification would be to increase the cost of coal sold to the Utilities or significantly reduce the recoverable reserves hereunder. B) Power System - SJCC shall provide or contract for its electric power requirements for mining by separate agreement. 7.2 Processing Methods A) SJCC shall process Mineable Coal, Alternate Coal, and/or Non-SJCC Coal in its facilities in accordance with accepted coal processing methods to meet Section 5.1 "Coal Size" and Section 5.2 "Coal Quality" requirements. B) Power System - SJCC shall provide or contract for its electric power requirements for processing by separate agreement. 7.3 Reclamation Activities A) SJCC will reclaim lands on the SJCC Site Area as required by and in compliance with all applicable laws, regulations and conditions of applicable permits, licenses and approvals. Utilities will compensate SJCC for all reclamation and related liabilities, obligations and costs associated with disturbance on the SJCC Site Area resulting in any way from the supply of coal to the San Juan Station; provided, however, that the Utilities' reclamation liability after any termination (but not expiration) is further limited to surface reclamation and related liabilities, obligations and costs, as more specifically provided in Section 12.5(D) "Liabilities Upon Termination". B) Post Term Reclamation - At a time designated by the Joint Committee, which in any event shall be no later than ten (10) years prior to expiration of this Agreement, Utilities agree to make arrangements, acceptable to SJCC to assure that Utilities' obligation to fully compensate SJCC for all reclamation obligations of SJCC for all of the SJCC Site Area will be satisfied. Unless otherwise agreed, such assurance shall include at least one or more of the following: bonding or other financial assurance, or funding of a secure reclamation account. SJCC's acceptance of such assurance shall not be unreasonably withheld. 16 C) Regulatory Costs - If SJCC is required by the provisions of agreements relating to the SJCC Site Area, or any regulations or directives issued pursuant thereto, or by the provisions of any statute, ordinance, regulation or other directive of any governmental body to undertake any reclamation, environmental protection or related work, compensation for which would not be covered under the provisions of Section 8 "SJCC Compensation", SJCC shall receive compensation from Utilities for complying with such reclamation, environmental protection or related work consistent with the compensation provisions of Section 8 "SJCC Compensation" to the extent that such activity is associated with disturbance on the SJCC Site Area resulting in any way from the supply of coal to the San Juan Station; provided, however, that the Utilities' liability for such work after any termination (but not expiration) is further limited to work related to surface mining and the surface effects of underground mining. The procedures for determining such compensation shall be agreed to by the Parties. 17 Section 8 - SJCC Compensation ----------------------------- 8.1 Compensation Components The Utilities shall pay to SJCC the sales price for coal delivered to Utilities ("Coal Costs"), and in addition shall reimburse SJCC for Other Costs as described in Section 8.5 "Other Costs". The Coal Costs to be paid by the Utilities is comprised of the following components: A) The Mining and Reclamation Component as described in Section 8.2 "Mining and Reclamation Component". B) The Coal Processing Component as described in Section 8.3 "Coal Processing Component". C) Non-SJCC Coal and Alternate Coal Costs as described in Section 8.4 "Non-SJCC Coal and Alternate Coal Costs". 8.2 Mining and Reclamation Component The Mining and Reclamation Component shall be the sum of the Base Capital Investment Element Amount ("Base CIE Amount") as described in Section 8.2(A), the Incremental Capital Investment Element Amount ("Incremental CIE Amount") as described in Section 8.2(B), SJCC's Reimbursable Operating Costs ("Reimbursable Operating Costs") as described in Section 8.2(C), the Administration Element as described in Section 8.2(D), and the Capital Investment Element Reconciliation Amount ("CIE Reconciliation Amount") as described in Section 8.2(E). A) Base CIE Amount Each month, Utilities shall pay to SJCC a base capital investment element that will be calculated and adjusted as herein provided. All adjustment results will be rounded to three decimal places unless specified otherwise. 1) For Mineable Coal and Alternate Coal, the Base Capital Investment Element is [*] per Ton ("Base CIEOriginal"). There are three adjustments that cumulatively comprise the Base CIE Adjustments. The Base CIEOriginal shall be adjusted in the order recited, as follows: (i) Capital True Up Adjustment. A one-time capital true up adjustment will be made, in dollars per Ton, pursuant to the Capital True Up Agreement. The Capital True Up Adjustment will be made according to the following formula: Base CIEtrue up adj = Base CIEOriginal + Capital True Up Adjustment (TRUE UP ADJ & ORIGINAL ARE SUBSCRIPTS) Where the Capital True Up Adjustment will be determined as provided for in the Capital True Up Agreement, if it is positive it will increase the Base CIEOriginal and if it is negative it will decrease the Base CIEOriginal. 18 (ii) Tax and Depletion Adjustment. In the event the tax ("T") and/or depletion ("PD") factors, as defined in Exhibit "G" "Tax Calculations", change, the Base CIEtrue up adj will be adjusted, as follows: Base CIEtax adj = Base CIEtrue up adj X [OBJECT OMITTED] Where Madj = [OBJECT OMITTED] Where, the Moriginal, NPVC, and NPVD values shall be determined as provided for in the Capital True Up Agreement. If T and PD have not changed, Base CIEtax adj shall be equal to the Base CIEtrue up adj. [TAX ADJ & TRUE UP ADJ ARE SUBSCRIPTS] (iii) Inflation-Deflation Adjustment. The Base CIEtax adj shall be further adjusted monthly, according to the following formula: Base CIE = Base CIEtax adj x D1 / D0 [1 AND 0 ARE SUBSCRIPTS] D1 and D0 are defined in Section 8.6 "Inflation - Deflation Adjustment". In no event shall the inflation-deflation adjustment cause the Base CIE to be less than the Base CIEtax adj. 2) For Non-SJCC Coal the Non-SJCC Base CIE will be determined each month as follows: (i) If the costs to SJCC of the Non-SJCC Coal plus the Base CIE is less than or equal to the Annual Interim Invoice Agreement Price (as defined in Section 8.7(B) "Interim Invoice"), the Non-SJCC Base CIE will be equal to the Base CIE. (ii) If the costs to SJCC of the Non-SJCC Coal plus the Base CIE is greater than the Annual Interim Invoice Agreement Price (as defined in Section 8.7(B) "Interim Invoice"), the Non-SJCC Base CIE will be the greater of: a) The Annual Interim Invoice Agreement Price minus the costs to SJCC of the Non-SJCC Coal or b) Zero (0). 19 3) Base Tons The SJCC Base Monthly Tons ("BMT") and the Non-SJCC Base Monthly Tons ("NBMT") shall be determined as follows: (i) The BMT shall be equal to the MMT unless the NMS are greater than zero and the SMS are less than the MMT, in which case the BMT shall be equal to the MMT minus the NBMT. (ii) The NBMT shall be equal to zero (0) unless the SMS is less than the MMT, in which case the NBMT shall be equal to the lesser of a) The MMT minus the SMS; or b) The NMS. 4) Monthly Base CIE Amount. The Monthly Base CIE Amount shall be the sum of: The Base CIE times the BMT; plus, The Non-SJCC Base CIE times the NBMT. B) Incremental CIE Each month, Utilities shall pay to SJCC, for each Ton of coal delivered during that month by SJCC above the MMT (defined herein), an incremental capital investment element calculated as described below: 1) For Mineable Coal and Alternate Coal the Incremental CIE is [*] and will not be subject to inflation or deflation. 2) For Non-SJCC Coal the Non-SJCC Incremental CIE shall be determined as follows. In each month that Non-SJCC Coal is sold under Non-Normal Conditions where an Uncontrollable Forces situation has not been declared, the Non-SJCC Incremental CIE will be equal to zero (0). If the Non-SJCC Coal is sold under Non-Normal Conditions where an Uncontrollable Forces situation has been declared, the Non-SJCC Coal will receive the Incremental CIE. 3) Incremental Tons The SJCC Incremental Monthly Tons ("IMT") and the Non-SJCC Incremental Monthly Tons ("NIMT") shall be determined as follows: (i) If the SMS are greater than the MMT, the IMT shall be equal to the SMS minus the MMT; otherwise the IMT shall be equal to zero (0). (ii) The NIMT shall be equal to the NMS minus the NBMT. 20 4) Monthly Incremental CIE Amount. The Monthly Incremental CIE Amount shall be the sum of: The Incremental CIE times the IMT; plus, The Non-SJCC Incremental CIE times the NIMT. C) Reimbursable Operating Costs Each month, Utilities shall pay to SJCC, SJCC's Reimbursable Operating Costs which shall be all Operating Costs defined in Exhibit "F" "Operating Costs" paid or incurred in connection with the sale of Mineable Coal including mining related reclamation costs incurred by SJCC hereunder. 1) Operating Costs that are eligible for the depletion allowance as defined in Exhibit "G" "Tax Calculations" shall be adjusted for income tax and depletion as provided below: Reimbursable Operating Costs = Operating Costs X [OBJECT OMITTED] Where T and PD are as defined in Exhibit "G" "Tax Calculations". 2) All other Operating Costs shall be reimbursed at 100%. D) Administration Element Each month, Utilities shall pay to SJCC, an Administration Element equal to [*] per month. The Administration Element shall be calculated and adjusted for i) tax and depletion, and ii) inflation and deflation as herein provided. Administration Element = [*] X [OBJECT OMITTED] Where T and PD are as defined in Exhibit "G" "Tax Calculations", and D1 and D0 are defined in Section 8.6 "Inflation - Deflation Adjustment". E) CIE Reconciliation Amount In the invoice for December of each year a CIE Reconciliation will be made if NAS are greater than zero (0) or if the SMS are less than the MMT for any month during the year. The CIE Reconciliation Amount (which can be negative) will be added to the December Invoice. The CIE Reconciliation Amount will be determined as follows: CIE Reconciliation Amount = Annual CIE Amount - CIE Amount Invoiced. Where; The CIE Amount Invoiced is equal to the sum of the Monthly Base CIE Amounts and the Monthly Incremental CIE Amounts invoiced during the year (including the December amounts). And, 21 The Annual CIE Amount is equal to the sum of: 1) The AA Base CIE multiplied by the BAT; plus, 2) The AA Non-SJCC Base CIE multiplied by the NBAT; plus 3) The Incremental CIE multiplied by the IAT; plus, 4) The AA Non-SJCC Incremental CIE multiplied by the NIAT. F) Definitions: 1) SJCC Monthly Sales ("SMS") shall be equal to the Tons of Mineable Coal and Alternate Coal delivered in a month. 2) Annual SJCC Sales ("SAS") shall be equal to the sum of the SMS for a calendar year. 3) Non-SJCC Monthly Sales ("NMS") shall be equal to the Non-SJCC Coal delivered in a month. 4) Non-SJCC Annual Sales ("NAS") shall be equal to the sum of the NMS for a calendar year. 5) Total Monthly Sales ("TMS") shall be the sum of the SMS and the NMS. 6) Total Annual Sales ("TAS") shall be the sum of the SAS and the NAS. 7) Minimum Annual Tons ("MAT") shall be defined as the Tons shown in column 2 labeled "Minimum Annual Tons" on Exhibit "H" "San Juan Station Minimum Deliveries 2003 - 2017" for each calendar year. 8) Minimum Monthly Tons ("MMT") shall be defined as the monthly portion of the MAT prorated based on the monthly tonnages provided pursuant to Section 4.2(B) "Delivery Rates" or as agreed to by the Parties. If there is not a monthly tonnage allocation of the MAT, the MMT shall be 1/12 of the MAT for each month. 9) Short Fall Tons ("SFT"), for any year, shall be defined as zero (0), unless SJCC has not declared an Uncontrollable Forces event and the TAS are less than the MAT in any year in which SJCC is obligated under the terms of this Agreement, to deliver coal in such amounts that the total Tons requested for said year would be greater than or equal to the MAT; in which case the SFT for such year shall be the MAT minus the TAS. 10) Weighted Average Annual Base CIE ("AA Base CIE") shall be equal to the sum of the products of the monthly Base CIE multiplied by the MMT for each of the 12 months, all divided by the MAT. 11) Weighted Average Annual Non-SJCC Base CIE ("AA Non-SJCC Base CIE") shall be equal to the sum of the products of the Non-SJCC Base CIE multiplied by the NBMT invoiced each month for each of the 12 months, all divided by the sum of the NBMT. 22 12) Weighted Average Annual Non-SJCC Incremental CIE ("AA Non-SJCC Incremental CIE") shall be equal to the sum of the products of the Non-SJCC Incremental CIE multiplied by the NIMT invoiced each month for each of the 12 months, all divided by the sum of the NIMT. 13) The Non-SJCC Base Annual Tons ("NBAT") shall be equal to zero unless the SAS is less than the MAT minus the SFT in which case the NBAT shall be equal to the lesser of: (i) The MAT minus the SFT minus the SAS or (ii) The NAS. 14) The SJCC Base Annual Tons ("BAT") shall be equal to the MAT minus the SFT, unless the NAS is greater than zero (0) and the SAS are less than the MAT minus the SFT, in which case the BAT shall be equal to the MAT minus SFT minus the NBAT. 15) If the SAS are greater than the MAT, the SJCC Incremental Annual Tons ("IAT") shall be equal to the SAS minus the MAT; otherwise the IAT shall be equal to zero (0). 16) The Non-SJCC Incremental Annual Tons ("NIAT") shall be equal to the NAS minus the NBAT. 8.3 Coal Processing Component The Coal Processing Component shall be the sum of the Processing Capital Investment Element Amount ("Processing CIE Amount") as described in Section 8.3(A), SJCC's Reimbursable Processing Costs ("Reimbursable Processing Costs") as described in Section 8.3(B), the Processing Administration Element as described in Section 8.3(C), and the Processing Capital Investment Element Reconciliation Amount ("Processing CIE Reconciliation Amount") as described in Section 8.3(D). A) Processing CIE Amount Each month, Utilities shall pay to SJCC, a Processing Capital Investment Element determined as described below: 1) The Processing CIEEligible-Org for the processing of Tons that are eligible for the depletion allowance as described in Exhibit "G" "Tax Calculations" shall be calculated to five decimal places monthly, as described below: [OBJECT OMITTED] Where: T and PD are as defined in Exhibit "G" "Tax Calculations". 23 2) Processing CIE for processing of Tons that are not eligible for the depletion allowance ("Processing CIENon-elg-Org") as described in Exhibit "G" "Tax Calculations" shall be calculated to five decimal places monthly as described below: [OBJECT OMITTED] Where: T and PD are as defined in Exhibit "G" "Tax Calculations". 3) Inflation - Deflation Adjustment - The Processing CIEEligible-Org and Processing CIENon-elg-Org shall be adjusted to three decimal places, monthly, as described below: Processing CIEEligible-Adj = Processing CIEEligible-Org x D1 / D0 [ELIGIBLE-ADJ, ELIGIBLE-ORG, 1 & 0 ARE SUBSCRIPTS] And Processing CIENon-elg-Adj = Processing CIENon-elg-Org x D1 / D0 [NON-ELG-ADJ & NON-ELG-ORG ARE SUBSCRIPTS] Where: D1 and D0 are defined in Section 8.6 "Inflation - Deflation Adjustment". In no event shall the inflation-deflation adjustment cause the Processing CIEEligible-Adj to be less than the Processing CIEEligible-Org or the Processing CIENon-elg-Adj. to be less than the Processing CIENon-elg-Org. 4) Underground Adjustment. The Processing CIEEligible-Adj and the Processing CIENon-elg-Adj, will be further reduced by [*] per Ton. This [*] reduction will not be subject to inflation or deflation adjustment. Processing CIEEligible = Processing CIEEligible-Adj - [*] [ELIGIBLE & ELIGIBLE-ADJ ARE SUBSCRIPTS] Processing CIENon-eligible = Processing CIENon-elg-Adj - [*] [NON-ELIGIBLE & NON-ELG-ADJ ARE SUBSCRIPTS] 5) The "Monthly Processing Tons" shall be one twelfth (1/12) of the annual tonnage set forth in Column 3 ("Annual Processing Tons") of Exhibit "H" "San Juan Station Minimum Deliveries 2003-2017" for said calendar year. (i) The "Monthly Eligible Processing Tons" shall be equal to the Monthly Processing Tons times the ratio of Mineable Coal sold to the TMS (Total Monthly Sales). If TMS is equal to zero (0), then Monthly Eligible Processing Tons shall be equal to Monthly Processing Tons. (ii) The "Monthly Non-Eligible Processing Tons" shall be equal to the Monthly Processing Tons times the ratio of Alternate Coal and Non-SJCC Coal sold to the TMS (Total Monthly Sales). 24 6) The Monthly Processing CIE Amount shall be the sum of: (i) The Monthly Eligible Processing Tons times the Processing CIEEligible; plus, (ii) The Monthly Non-Eligible Processing Tons times the Processing CIENon-eligible. B) Reimbursable Processing Costs Each month, Utilities shall pay to SJCC all Operating Costs defined in Exhibit "F" "Operating Costs" paid or incurred in connection with the processing of Mineable Coal, Non-SJCC Coal and Alternate Coal: 1) all Rental and Royalties and all Taxes, as defined in Paragraphs A and G of Exhibit "F" "Operating Costs", paid or incurred in connection with the processing of coal mined by SJCC hereunder; plus, 2) all Operating Costs defined in Exhibit "F" "Operating Costs" (excluding said Rentals and Royalties, and Taxes referred to in Section 8.3(B)(1)) that are eligible for the depletion allowance will be adjusted as described below: Depletion-eligible Reimbursable SJCC Coal Processing Costs = SJCC Processing Costs X [OBJECT OMITTED] Where T and PD are as defined in Exhibit "G" "Tax Calculations"; plus, 3) all of SJCC's Operating Costs, as defined in Exhibit "F" "Operating Costs" (excluding said Rentals and Royalties, and Taxes referred to in Section 8.3(B)(1)) that are not eligible for the depletion allowance will be adjusted as described below: Depletion-ineligible Reimbursable SJCC Coal Processing Costs = SJCC Processing Costs X [*]. C) Processing Administration Element Each month, Utilities shall pay to SJCC a Processing Administration Element comprised of the sum of the following elements: 1) The portion of the Processing Administration Element that is eligible for the depletion allowance shall be calculated and adjusted for i) tax and depletion, and ii) inflation and deflation as follows: 25 Eligible Processing Administration Element = [*] X [OBJECT OMITTED] X Mineable Coal % Where T and PD are as defined in Exhibit "G" "Tax Calculations", and D1 and D0 are defined in Section 8.6 "Inflation - Deflation Adjustment", and Mineable Coal % is equal to the Tons of Mineable Coal sold divided by the TMS (Total Monthly Sales) expressed as a percentage. If TMS is equal to zero (0), then Mineable Coal % shall be equal to one hundred percent (100%). 2) The portion of the Processing Administration Element that is not eligible for the depletion allowance shall be calculated and adjusted for inflation and deflation as follows: Non-Eligible Processing Administration Element = [*] X [OBJECT OMITTED] X Non-Eligible Coal % Where, D1 and D0 are defined in Section 8.6 "Inflation - Deflation Adjustment", and Non-Eligible Coal % is equal to one hundred percent (100%) minus Mineable Coal %. D) Processing CIE Reconciliation Amount In any year in which Uncontrollable Forces have not been declared and the TAS are less than the annual tonnage set forth in column 3 of Exhibit "H" "San Juan Station Minimum Deliveries 2003-2017" for said calendar year and in which SJCC was obligated under the terms of this Agreement to process coal in such amounts that the total Tons requested to be processed for said year would be equal to or greater than the annual tonnage set forth in column 3 of Exhibit "H" "San Juan Station Minimum Deliveries 2003-2017" SJCC shall make an adjustment to the December invoice as herein follows: Processing CIE Reconciliation Amount is equal to the average of monthly Processing CIEs times [TAS minus the annual tonnage set forth in column 3 of Exhibit "H" "San Juan Station Minimum Deliveries 2003-2017" for the applicable calendar year]. 8.4 Non-SJCC Coal and Alternate Coal Costs Each month, Utilities shall pay to SJCC all of SJCC's costs of acquiring and selling Non-SJCC Coal and Alternate Coal for use by Utilities in the San Juan Station, including, without limitation, all costs described in Exhibit "F" "Operating Costs" incurred incident to any agreement for the purchase of Non-SJCC Coal and Alternate Coal and the negotiation thereof, provided that, the Joint Committee has approved all costs associated with the acquisition of such Non-SJCC Coal and Alternate Coal and such Non-SJCC Coal and Alternate Coal has been acquired by SJCC for processing and delivery under this Agreement as provided for herein. 26 8.5 Other Costs A) Other Reclamation Each month, Utilities shall pay to SJCC all Operating Costs, as defined in Exhibit "F" "Operating Costs" paid or incurred in connection with performance of other SJCC Site Area reclamation pursuant to Section 7.3 "Reclamation Activities". B) Substitute REI Utilities shall pay to SJCC an amount that is annually equal to the REI (as defined in the Fruitland Coal Sublease) multiplied by "X" (which may be negative). The monthly invoiced amounts will be based on the projected number of Fruitland Substitute Tons (defined below) and Fruitland Tons (defined below) for the year. Where: X=A-G And A=The number of Fruitland Substitute Tons is defined as all Tons except Fruitland Tons delivered to SJGS by SJCC, excluding the first [*] Tons other than those subject to the Fruitland Coal Sublease, provided, however, that the number of Fruitland Substitute Tons in any year will not exceed the greater of (i) the REI Minimum (as defined below) plus the REI Shortfall Balance as of the previous year end (as defined below) less the Fruitland Tons, or (ii) zero (0). B=The aggregate cumulative number of Make-up Tons (as defined in the Fruitland Coal Sublease) as of the previous year end. C=The REI Shortfall Balance as of the previous year end. The REI Shortfall Balance for 2002 year end is zero (0). The ending REI Shortfall Balance for each year thereafter will be the greater of (i) the sum of the ending REI Shortfall Balance for the previous year and the REI Shortfall Tons (as defined below) for the year, or (ii) zero (0). D=The number of Fruitland Tons is defined as the actual number of Tons mined and delivered from the Fruitland Leases (as defined in the Fruitland Coal Sublease) during the year. E=The REI Minimum, that shall be equal to the Annual Tonnage defined in the Fruitland Coal Sublease. F=(D-E-C), or zero (0), whichever is greater and G=(B-C), or F, whichever is less. REI Shortfall Tons means for any year the REI Minimum for that year less the sum of Fruitland Tons and Fruitland Substitute Tons for that year. (REI Shortfall Tons may be negative). 27 C) Payments under Cimarron Coal Assignment Each month, Utilities shall pay to SJCC all of SJCC's costs and obligations, if any, arising from the Cimarron Coal Assignment. D) Payments under the Ute ROW Each month, Utilities shall pay to SJCC all of SJCC's costs and obligations, if any, arising from the Ute ROW. E) Other Miscellaneous Costs Each month, Utilities shall pay to SJCC all Operating Costs, as defined in Exhibit "F" "Operating Costs" paid or incurred in connection with Other Costs. 8.6 Inflation - Deflation Adjustment A) The "Inflation Index", calculated to three decimal places, shall be equal to the sum of [*] times the "Producer Price Index - Commodities for Construction Machinery and Equipment (Series Id WPU112)" not seasonally adjusted, as published by the United States Department of Labor, Bureau of Labor Statistics ("Index"), plus [*] times the "Implicit Price Deflator, Gross Domestic Product", as published by the United States Department of Commerce, Bureau of Economic Analysis ("Deflator"). 1) D0 shall be the Inflation Index calculated using the most recently published values for June 2000, for the Index and Deflator. 2) D1 shall be the Inflation Index calculated using the most recently published values available for the date of the invoice, for the Index and Deflator. B) The factors D0 and D1 determined when the final UG-CSA invoice is issued, as described above, will not be further adjusted even though the Index and Deflator may be further revised. C) The following matters are made a responsibility of the Joint Committee to be carried out as provided for in Section 10 "Joint Committee": 1) Revision of a base index figure as derived from a published index in the event of a change in the base point of such latter index, in accordance with pertinent published instructions regarding such revision, or if no such instructions be published, a proportionate revision which will fairly reflect any such change in the base point. 2) Development of a mutually acceptable substitute index (either published or compiled or arranged by the Parties) in the event that publication of any of the published indices specified for use under this Section 8 should be discontinued or in the event the items or categories upon which such published index is based should be so modified or changed as to make the further use of such index inequitable, and any needed subsequent revisions of such a substitute index. 28 8.7 Invoicing and Settlement The accounting and billing period under this Agreement shall be one month. Such one-month period shall be a fiscal month (currently defined as a calendar month) as adopted by SJCC unless the Joint Committee shall specify a different one-month period. SJCC shall send to Utilities monthly invoices for the compensation due to SJCC for the month in question. Both Utilities and SJCC recognize that some of the information applicable to an invoice may not be available at the time the invoice is prepared by SJCC and submitted to Utilities. In such event, the submitted invoice shall be based upon the best available information. Upon receipt of such formerly unavailable information SJCC shall prepare and furnish to Utilities a supplemental invoice. SJCC shall prepare and provide the Utilities with a UG-CSA Invoice and an Interim Invoice each month. Utilities shall make payments to SJCC based on the Interim Invoice. A) UG-CSA Invoice UG-CSA Invoices submitted hereunder shall set forth in reasonable detail the following in a format to be agreed upon by the Parties: 1) Coal Costs (i) The Mining and Reclamation Component a) Base CIE Amount b) Incremental CIE Amount c) Reimbursable Operating Costs d) Administration Element e) CIE Reconciliation Amount (ii) The Coal Processing Component a) Processing CIE Amount b) Reimbursable Processing Costs c) Processing Administration Element d) Processing CIE Reconciliation Amount (iii)Non-SJCC Coal and Alternate Coal Costs 2) Other Costs (i) Other Reclamation (ii) Substitute REI (iii)Payments under Cimarron Coal Assignment (iv) Payments under the Ute ROW (v) Other Costs 29 B) Interim Invoice The Parties, by mutual agreement, shall negotiate an Annual Interim Invoicing Agreement to govern the monthly invoicing of coal. The Annual Interim Invoice Agreement Price shall be the average annual price for all Mineable Coal pursuant to the Annual Interim Invoicing Agreement. In the event the Parties are unable to mutually agree on an Annual Interim Invoicing Agreement the Interim Invoice will be determined as follows: 1) The base price or equivalent from the prior year's Interim Invoicing Agreement, adjusted for the prior year UG-CSA Invoice to Interim Invoice true up, will be the base price for the MMT. 2) The prior year's incremental price will be the incremental price for all Tons above the MMT. 3) There will be an adjustment to the December Interim Invoice to make the amounts received from the monthly Interim Invoices equal to the amount that would have been due based on the UG-CSA Invoices. C) Settlement and Payment Invoices submitted by SJCC in accordance with Section 8.7 "Invoicing and Settlement" and any supplemental or true-up invoices shall be due and payable by Utilities on the twenty-second (22nd) day of the month succeeding the month for which such invoice is submitted, or on the twelfth (12th) day after receipt of the invoice by Utilities, whichever date is later. Payment shall be made to SJCC by electronic funds transfer to such bank account as SJCC may from time to time designate. D) Accounting Records SJCC shall maintain its accounts and records in accordance with generally accepted accounting principles consistently applied. SJCC shall retain such accounts and records for any calendar year for five (5) years following the end of such calendar year and for such reasonable additional period as specifically requested by Utilities. E) Disputed Invoices In case any portion of an invoice shall be in dispute, the undisputed amount shall be paid when due; provided however, that Utilities may also pay the disputed portion of such invoice without thereby waiving their right to contest such disputed portion. F) Failure to Pay In the event Utilities fail to pay any amount due and not in bona fide dispute, Utilities shall pay SJCC interest on all amounts owing under any invoice submitted hereunder which are not paid when due and payable, with said interest to be calculated at the Prime Rate as published in the Wall Street Journal for corporate loans posted by at least 75% of the nation's largest banks (or its equivalent) plus three 30 percent (3%) but not in excess of the maximum rate of interest permitted by law and to be paid for the actual number of days elapsed from and including the date the invoice was due and payable until funds are received in SJCC's account. This right shall not be deemed an exclusive right or remedy. G) Suspension of Payment for Failure to Deliver In the event SJCC fails to deliver coal, which failure to deliver is not caused by Utilities, and which failure to deliver is not excused by the provisions of Section 12.2 "Uncontrollable Forces" hereof, and if such failure to deliver continues for ten (10) days after final demand for delivery by Utilities, Utilities shall have the right to suspend payment for any coal previously delivered by SJCC until coal deliveries shall have been recommenced. This right shall not be deemed an exclusive right or remedy. H) Audits SJCC will keep books, records and accounts necessary to show all information required for purposes of this Agreement. Upon Utilities' request, SJCC shall supply Utilities, by report and/or with actual source documents, the information reasonably necessary to verify any invoice rendered to Utilities pursuant to this Agreement; provided, however, that SJCC shall not be required to disclose information which in the opinion of SJCC is of a confidential nature due to the relationship of such information to SJCC's existing or contemplated operations. In the event Utilities and SJCC are unable to agree that the invoice is calculated correctly, a verification of such invoice shall be prepared and certified by a nationally recognized firm of certified public accountants, to be selected by Utilities from a list of three (3) such firms submitted by SJCC, such verification to set forth all data reasonably necessary to verify that the invoice is calculated correctly. The findings of said verification shall be accepted by both Utilities and SJCC as final and binding with respect to that invoice. The accounting firm selected for any such verification shall be bound not to disclose and shall treat as confidential any and all proprietary information of SJCC furnished to or examined by such firm in connection with such audit. It is understood that such verification shall not provide Utilities with nor entitle Utilities to access to SJCC's books or records. If any such verification discloses that a calculation error has occurred and that, as a result thereof, an amount is due to one or the other party, such amount shall promptly be paid to whom it is owed; provided, however, if there is a dispute relating to the validity of a charge or adequacy of a payment either party may submit such dispute to the Joint Committee. All expenses of any such requested verification shall be paid by Utilities. Invoices which are not contested by either party within twenty-four (24) months from the date of the Invoice shall be deemed to be correct and will not thereafter be subject to verification. 31 Section 9 - Coordinating Committee ---------------------------------- 9.1 Purpose The intent of the Parties in providing for a Coordinating Committee is to establish an orderly and continuing means of dealing with certain engineering and operating problems which may arise from time to time in carrying out the provisions of this Agreement. The Coordinating Committee shall have two (2) members and shall be responsible for making decisions concerning said engineering and operating problems which may arise from time to time under this Agreement, including those matters expressly specified herein. 9.2 Designation During the term of this Agreement, SJCC will, by notice to Utilities, designate an individual as its representative on the Coordinating Committee and Utilities will, by notice to SJCC, together designate one (1) individual as their representative on the Coordinating Committee and each such representative shall be authorized by the party(ies) by whom he is designated to act on its (their) behalf with respect to matters herein specified to be the responsibilities of the Coordinating Committee, but shall have no authority to amend this Agreement. A representative may not delegate his responsibilities to others, but Utilities, or SJCC, may designate an alternate to act when the representative is unavailable. Either Utilities, or SJCC, by notice to the other, may change the designation of its (their) representative. 9.3 Procedures and Practices It shall be the responsibility of the Coordinating Committee to establish or approve, for the guidance of the local operating personnel of the respective Parties, procedures and standard practices, consistent with the provisions of this Agreement, with respect to: A) Changes in the 24-hour period used in computing the average heating value of coal delivered pursuant to Section 5.2 "Coal Quality". B) Operations involved in the delivery of coal per Section 4 "Delivery of Coal" and in the weighing, sampling and analysis of coal pursuant to Section 5.4 "Weighing and Analysis Facilities and Methods". C) Operating, accounting and reporting details required to carry out the provisions of this Agreement with respect to invoicing and settlement pursuant to Section 8.7 "Invoicing and Settlement". D) Exchange of technical information and data pertinent to coal mining, reclamation and delivery operations under this Agreement. E) Any other matters expressly made the responsibility of the Coordinating Committee under the terms of this Agreement. 32 9.4 Coordinating Committee Decisions The establishment or approval of a procedure or standard practice shall be evidenced by the signatures of both representatives of the Coordinating Committee. 9.5 Relationship to Joint Committee and Arbitration If the Coordinating Committee fails to resolve matters referred to it pursuant to this Agreement, such matters shall be submitted to the Joint Committee for resolution as provided for in Section 10 "Joint Committee". 33 Section 10 - Joint Committee ---------------------------- 10.1 Purpose The intent of the Parties in providing for a Joint Committee is to establish an orderly and continuing means of dealing with major matters which may arise from time to time in carrying out the provisions of this Agreement and for the resolution of matters which cannot be resolved by the Coordinating Committee, as more specifically defined below. The Joint Committee shall have four (4) members. 10.2 Designation During the term of this Agreement, SJCC will, by notice to Utilities, designate two (2) individuals as its representatives on the Joint Committee, and Utilities will, by notice to SJCC, designate two (2) individuals as their representatives on the Joint Committee; and each such representative shall be authorized by the party(ies) by whom he is designated to act on its (their) behalf with respect to matters herein specified to be responsibilities of the Joint Committee. A representative may not delegate his responsibilities to others, but Utilities, or SJCC, may designate an alternate to act when said representative is unavailable. Either Utilities, or SJCC, by notice to the other, may change the designation of its (their) representatives. 10.3 Authority The Joint Committee shall have the following authority, and shall have the responsibility to act if appropriate, with respect to the following matters: A) Review and approval of an annual operating cost budget, which shall be proposed and submitted by SJCC prior to October 1 of each calendar year. The annual operating cost budget shall include a schedule of service contracts with an annual value greater than $1,000,000. It is recognized that this dollar limit may not be sufficient throughout the duration of this Agreement, and it shall therefore be the responsibility of the Joint Committee to review said dollar limit, no less often than every five (5) years, and to determine adequate dollar limits for the then current conditions. Utilities shall approve or disapprove the annual operating cost budget within thirty (30) days after submission by SJCC. Unless Utilities shall disapprove the annual operating cost budget within said time period, the same shall be deemed approved. However, in the event that Utilities shall not approve the annual operating cost budget, SJCC shall nonetheless be empowered to make such operating expenditures as it shall reasonably deem necessary in order to perform its obligations hereunder, and the reasonableness of such expenditures shall be submitted to and determined by arbitration as provided for in Section 11 "Dispute Resolution". With regard to any approved annual operating cost budget, SJCC shall be paid its Operating Costs in accordance with this Agreement as follows: 1) in the event that Operating Costs paid or incurred by SJCC do not exceed one hundred fifteen percent (115%) of the Operating Costs contained in said budget, SJCC shall be paid all of its Operating Costs; 34 2) in the event Operating Costs paid or incurred by SJCC exceed in amount the Operating Costs payable to SJCC pursuant to the immediately preceding Section 10.3(A)(1), then SJCC shall be paid its Operating Costs to the extent that the same would be payable in accordance with the immediately preceding Section 10.3(A)(1), and either Utilities or SJCC may submit to the Joint Committee the question of the appropriateness of the Operating Costs in excess of such reimbursed amount. In conjunction with said approval of the annual operating cost budget, SJCC shall give Utilities a map showing the areas planned to be mined by SJCC in the following year and the sequence of mining planned by SJCC in each such area. B) Review of changes not anticipated in the latest annual operating cost budget if budgeted expenditures are materially affected. C) Review a capital budget that shall be provided by SJCC at the same time as the annual operating cost budget for informational purposes. D) Establish policies, programs and procedures for: 1) determination of the level of reimbursement, if any, of SJCC's Operating Costs to be paid during periods when SJCC is unable to mine, process and sell coal by reason of Uncontrollable Forces, and; 2) determination of the level of coal to be purchased and paid for by Utilities, if any, during periods when operation of the San Juan Station is materially curtailed or prevented by Uncontrollable Forces (it being agreed that in such event the obligation of Utilities to purchase and pay for coal, and to make any other payments under this Agreement, shall be deferred unless otherwise determined by the Joint Committee). E) Consider and attempt to resolve any disputes which may be referred to the Joint Committee. F) Consider the enlargement of the space made available to SJCC at the San Juan Station site pursuant to Section 6.2 "SJCC's Facilities". G) Consider any other matters expressly made the responsibility of the Joint Committee under the terms of this Agreement, including, but not limited to, the responsibilities set forth in Section 3.2 "Alternate Coal". 10.4 Decisions by the Joint Committee Decisions by the Joint Committee shall require the unanimous approval of all representatives of the Joint Committee and shall be evidenced by the signatures of all said representatives. 35 10.5 Relationship to Arbitration If the Joint Committee fails to resolve matters referred to it pursuant to this Agreement, such matters may be submitted to and determined by arbitration as provided for in Section 11 "Dispute Resolution". 36 Section 11 - Dispute Resolution ------------------------------- 11.1 Matters To Be Arbitrated; Notice of Claims and Defenses; Party Arbitrator Designation Either party may demand final and binding arbitration of any dispute, claim or controversy arising out of or relating to this Agreement, performance or actions pursuant to this Agreement, or concerning the interpretation of this Agreement (whether such matters sound in contract, tort or otherwise and including without limitation repudiation, illegality, and/or fraud in the inducement) by giving written notice to the other party of all claims it desires to submit to arbitration; provided, however, that matters within the authority of the Joint Committee must be presented first to that committee for consideration. The notice shall include: (a) the demanding party's designation of a party arbitrator; and (b) a detailed statement of the facts and theories supporting the claims. The party on whom the arbitration demand is served shall have thirty days from receipt of the notice to respond in writing to the demand and to submit any additional claims it wishes to submit to arbitration at the same time. The response also shall include: (a) the designation of the party arbitrator for that party; and (b) a detailed statement of the facts and theories supporting the claims and/or defenses asserted. The party originally demanding arbitration shall reply in writing to any additional claims submitted within ten days from the receipt of such response. 11.2 Arbitrators; Selection of Neutral Arbitrator Any party who fails to designate timely its party arbitrator shall forfeit its right to designate an arbitrator. If only one arbitrator is timely designated, that single arbitrator shall hear the dispute. If two arbitrators are timely designated, those arbitrators shall, within thirty days, either agree on the appointment of a third, disinterested arbitrator knowledgeable as to the subject matter involved in the arbitration or petition the Chief Judge of the United States District Court for the District of New Mexico for the appointment of a third arbitrator. The parties shall be equally liable for the reasonable fees and expenses of the neutral arbitrator hearing the dispute. The parties shall be responsible for the fees and expenses of their respective party-appointed arbitrator. 11.3 Arbitration Hearings, Procedures and Timing All reasonable efforts will be made to hold a hearing on the claims submitted within sixty days after the appointment of the last arbitrator. In conducting the hearing, the arbitrators are directed, where feasible and where not inconsistent with the provisions of this section, to adhere to the then-existing American Arbitration Association procedures and rules relating to commercial disputes. Unless otherwise agreed by the parties, the hearing shall be held in Farmington, New Mexico. 11.4 Choice of Law The arbitrators shall apply the laws of the State of New Mexico. 37 11.5 Award and Enforcement The decision or award of the arbitrators shall be given in writing within thirty days after the conclusion of the hearing. The arbitrators are authorized to award money damages, injunctive and declaratory relief and/or specific performance, if such relief in their opinion is appropriate. In any arbitration, each party shall bear its own costs, expenses, and attorneys' fees. The arbitrators do not have authority to award costs, expenses, or attorneys' fees to the prevailing party. The award or decision of the arbitrators shall be subject to review or enforcement in accordance with the New Mexico Uniform Arbitration Act, NMSA 1978 ss.ss. 44-7-1 et seq. Any party shall be entitled to recover reasonable attorneys' fees and costs incurred in enforcing any arbitration award or decision made pursuant to the arbitration provisions of this Agreement. 11.6 Performance Pending Arbitration Decision During the arbitration, unless otherwise ordered by the arbitrators, the parties shall continue to perform under this Agreement. 11.7 Definition of "Party" for this Section For purposes of this Section 11 the Utilities shall be considered a single party. Specifically, and by example, Utilities must act collectively to select their party-appointed arbitrator under Section 11.3 "Arbitration Hearings, Procedures and Timing". 38 Section 12 - Non-Normal Conditions, Right to Cure, Termination and Expiration ----------------------------------------------------------------------------- 12.1 Utilities' Right to Mine A) Emergency Situation. An emergency situation shall be deemed to have arisen if, for any reason, including Uncontrollable Forces, SJCC shall be unable to maintain deliveries of coal as required of SJCC hereunder and BHP Minerals International Inc. shall fail to cause such deliveries to be made pursuant to the Guarantee ("Emergency Situation"). B) Mining and Delivery of Coal by Utilities. In the event that an Emergency Situation as set forth in Section 12.1(A) above should arise and Utilities are able to cause such deliveries to be made, then in such event Utilities may go upon the SJCC Site Area and, using SJCC's equipment, mine coal therefrom and deliver such coal. If Utilities undertake such operations, SJCC will have its supervisory personnel direct and assist Utilities in such operation. C) Termination of Emergency Situation. Such operations by Utilities shall terminate on notice from SJCC when SJCC is able to resume normal coal deliveries to Utilities. 12.2 Uncontrollable Forces Neither party shall be deemed in default of any obligation under this Agreement, and performance of such obligation shall be deferred during such period as and to the extent that performance is prevented by reason of Uncontrollable Forces, the term "Uncontrollable Forces" meaning any cause beyond the control of the party affected which by exercise of due diligence it shall be unable to overcome, including, without limitation, failure of plant or facilities, flood, earthquake, storm, lightning, fire, explosion, epidemic, war, riot, civil disturbance, labor stoppage, sabotage, restraint by court or public authority, or the necessity for compliance with any applicable law, regulation, ordinance or resolution. Neither party shall, however, be relieved of liability for failure of performance if such failure be due to causes arising out of its own negligence or to causes which it could, but fails to, remove or remedy with reasonable dispatch. Nothing herein contained shall be construed to obligate a party to forestall or settle a labor dispute against its will. All times and periods for the performance of any obligation in this Agreement shall be extended by the period during which performance is prevented by Uncontrollable Forces. 12.3 Non-Normal Conditions, Right to Cure, and Offers of Non-SJCC Coal. The Parties intend that in the effort to avoid Material Default, the provisions of this Section 12.3 shall be utilized before notice of Material Default Conditions (defined in Section 12.4(A) "Material Default Conditions") is provided pursuant to Section 12.4(C) "Notice of Material Default Condition(s)". A) Non-Normal Conditions. Non-Normal Conditions exist when any of the following three conditions are present: 39 1) The Reserve of Coal is below the level of 1.2 million Tons, 2) SJCC has determined that there is a reasonable probability that the Reserve of Coal will in the near future fall below the level of 1.2 million Tons, or 3) SJCC anticipates or is experiencing any other condition that may prevent SJCC from delivering coal according to this Agreement. B) Notice. SJCC shall provide written notice to the Utilities if any Non-Normal Conditions exist, or the Joint Committee may determine that Non-Normal Conditions exist, which shall constitute notice to SJCC and the Utilities as of the date of such written determination. C) Prevention Due to Uncontrollable Forces. In addition to providing written notice of Non-Normal Conditions, SJCC may elect to declare that the performance is prevented by reason of Uncontrollable Forces in accordance with the terms of Section 12.2 "Uncontrollable Forces". D) Coal Usage Forecast. Within fifteen (15) days after receipt of notice of Non-Normal Conditions, the Utilities will review dispatch at San Juan Station and provide to SJCC an updated coal usage forecast. E) Cure of Non-Normal Conditions. The Parties intend that cooperation among the Parties in developing and agreeing upon a Cure Plan (as defined below) is preferable to pursuing termination of this Agreement. The Parties will provide reasonable cooperation to facilitate SJCC's cure of Non-Normal Conditions to avoid Material Default while allowing the Utilities to continue operation of the San Juan Station. To initiate and effectuate cure of the Non-Normal Condition, SJCC shall do the following: 1) Provide within fifteen (15) days after notice of Non-Normal Conditions, or as otherwise agreed to by the Parties, a written cure plan to the Joint Committee describing SJCC's proposed means of curing the Non-Normal Conditions and its proposed deliveries in the interim ("Cure Plan"); 2) Within thirty (30) days after notice of Non-Normal Conditions, or as otherwise agreed to by the Parties, SJCC may provide written offers to the Utilities to supply Non-SJCC Coal. If the Non-Normal Conditions are caused by Uncontrollable Forces, then such Non-SJCC Coal will be priced as Alternate Coal. If there is a dispute whether the Non-Normal Conditions are caused by Uncontrollable Forces, the Non-SJCC Coal will be priced as Alternate Coal and will be re-priced as Non-SJCC Coal if necessary when the dispute is resolved. If the Non-Normal Conditions are not caused by Uncontrollable Forces, then, the Non-SJCC Coal shall be priced as described in Section 8 "SJCC Compensation". 40 SJCC will provide coal quality information for the Non-SJCC Coal with the written offers and will propose the delivery schedule and quantity of Non-SJCC Coal to be supplied. 3) Within fifteen (15) days after receipt of a proposed Cure Plan, the Joint Committee shall meet to consider and act on the Cure Plan. 4) Within fifteen (15) days after receipt of an offer to supply Non-SJCC Coal, the Joint Committee will meet to approve or reject the Non-SJCC Coal offer. Failure to approve the offer shall constitute its rejection. 5) For offers of Non-SJCC Coal only, SJCC will meet the revised coal minimum quality standard of at least 8700 BTU per pound measured as provided in Section 5.2 "Coal Quality". 6) As part of its Cure Plan, SJCC will provide weekly written notice to the Utilities of daily inventory levels of the Reserve of Coal. F) Rejection of Non-SJCC Coal. If the Joint Committee rejects an offer of Non-SJCC Coal that is proposed, and if the price of that Non-SJCC Coal offer is [*], then the offer of Non-SJCC Coal will be credited as coal delivered for the sole purpose of determining whether a Material Default Condition exists, unless the Joint Committee agrees that the Non-Normal Condition is due to Uncontrollable Forces, in which case Material Default provisions are inapplicable. G) Rejection of Non-SJCC Coal after Initial Approval. If the Utilities determine and the Joint Committee agrees that delivery of coal from a certain Non-SJCC Coal source is shown to materially impair operations at the San Juan Station, the Utilities may reject the unburned portion of that coal and, if so, SJCC shall terminate delivery of that coal. The remainder of such rejected coal shall not be credited as coal delivered for purposes of determining whether a Material Default Condition exists. H) Termination of Non-Normal Conditions. The Non-Normal Conditions will terminate when all of the following occur: 1) The Reserve of Coal exceeds 1.2 million Tons; 2) SJCC can supply the quantities of coal required by this Agreement from the Coal Leases, Remnant Coal, or Alternate Coal and/or previously acquired Non-SJCC Coal; 3) SJCC can meet the coal quality specifications described in Section 5.2 "Coal Quality"; and 4) SJCC gives written notice of the termination of Non-Normal Conditions. 41 12.4 Material Default. A) Material Default Conditions. The existence of any of the following material default conditions ("Material Default Conditions") may result in a Material Default by SJCC: 1) Failure of SJCC to deliver coal as specified in Section 4.2 "Delivery Rates" such that: (i) A ten percent (10%) per month or greater shortfall in deliveries as set forth in Exhibit "D" "Delivery Rates" occurs in any six (6) consecutive months (as adjusted pursuant to Section 12.3(F) "Rejection of Non-SJCC Coal"); or (ii) A cumulative shortfall of sixty percent (60%) in deliveries as set forth in Exhibit "D" "Delivery Rates" occurs over any three (3) month period (as adjusted pursuant to Section 12.3(F) "Rejection of Non-SJCC Coal"); 2) Failure of SJCC to comply with the requirements of Section 5.2 "Coal Quality" (as amended by Section 12.3(E)(5) in the event that Non-SJCC Coal is supplied under Non-Normal Conditions); 3) Failure of SJCC to maintain a Reserve of Coal greater than 250,000 Tons. The occurrence of any of the above conditions is not itself a Material Default B) Material Default exists when: 1) One or more of the Material Default Conditions exist; 2) Notice is provided pursuant to Section 12.4(C) "Notice of Material Default Condition(s)", and, 3) SJCC fails to avoid Material Default under Section 12.4(D) "Avoidance of Material Default". C) Notice of Material Default Condition(s). SJCC shall not be in Material Default under this Agreement unless and until SJCC shall have received from Utilities written notice of one or more Material Default Conditions specifying the particulars. SJCC may seek to avoid or cure the Material Default Condition(s) pursuant to the provisions of Section 12.4(D) "Avoidance of Material Default". SJCC shall not be conclusively deemed in Material Default if SJCC disputes the existence of any alleged Material Default unless and until there is a final resolution pursuant to Section 11 "Dispute Resolution" of this Agreement to determine the existence or non-existence of Material Default. D) Avoidance of Material Default. SJCC can prevent any of the Material Default Conditions from becoming a Material Default by any one or more of the following actions: 42 1) SJCC proceeds with due diligence to cure the alleged Material Default Condition(s) within thirty (30) days after receipt of the notice of Material Default Condition(s); 2) BHP Minerals International Inc. proceeds with due diligence to cure the alleged default within thirty (30) days of receipt of the notice of Material Default Condition(s); 3) SJCC declares prevention of performance by reason of Uncontrollable Forces pursuant to Section 12.2 "Uncontrollable Forces", and that declaration is not subsequently invalidated by arbitration; 4) SJCC gives notice of Non-Normal Conditions and operates according to a Cure Plan approved by the Joint Committee; or 5) SJCC disputes the existence of Material Default Condition(s), and there is a final resolution pursuant to Section 11 "Dispute Resolution" that SJCC was not in Material Default hereunder. E) Utilities' Remedies for SJCC's Material Default. Upon a Material Default caused by the existence of a Material Default Condition that is not avoided pursuant to Section 12.4(D) "Avoidance of Material Default", the Utilities shall have the following remedies: 1) The Utilities may terminate this Agreement for Material Default. Upon termination for Material Default, the Utilities shall have the options set forth in Section 12.5 "Termination". 2) Only in the event of an Emergency Situation as provided in Section 12.1 "Utilities' Right to Mine", Utilities or Utilities' agents may, in lieu of seeking termination or any other remedy, go upon the SJCC Site Area, use SJCC's equipment to mine coal therefrom, and deliver such coal to the Delivery Points. The compensation to be paid by Utilities to SJCC for such use of SJCC's equipment shall be agreed upon by the Joint Committee. Such operations by Utilities shall terminate when SJCC gives notice and is able to assume normal deliveries. 3) In addition to the rights provided in Section 12.5 "Termination" to termination and the limited right to mine, Utilities shall have any other remedies provided by law, subject to the waiver of consequential damages in Section 14.16 "Waiver of Consequential Damages". 12.5 Termination A) Options of Utilities Upon Termination. Upon termination of this Agreement for Material Default, in addition to other remedies provided in Section 12.4(E) "Utilities' Remedies for SJCC's Material Default" the Utilities shall have the option to: 43 1) Acquire SJCC's rights, title and interest in and to any or all of SJCC's plant and capital equipment used by SJCC in carrying out its obligations under this Agreement and the Coal Leases and other leases within the SJCC Site Area including all of SJCC's permits and reclamation bonds, paying SJCC therefore in cash the greater of the fair market value of SJCC's plant and capital equipment, and Coal Leases as determined by the Joint Committee, or SJCC's book cost net of depreciation of said plant and capital equipment, and the net value of the acquisition cost of the Coal Leases and other leases in the SJCC Site Area; 2) Require SJCC to dispose of any or all of SJCC's plant and capital equipment used by SJCC in carrying out its obligations under this Agreement, and interest in the Coal Leases and other leases in the SJCC Site Area including all of SJCC's permits and reclamation bonds, for cash at prevailing market prices and to pay SJCC all costs of disposal plus the amount, if any, by which SJCC's book cost net of depreciation of said plant and capital equipment, and the net value of the acquisition cost of the Coal Leases and other leases in the SJCC Site Area exceed the amount received by SJCC on account of the disposal thereof; or 3) Exercise neither of the above options, in which case SJCC shall retain such property interests as are necessary for the time required to satisfy all reclamation and other obligations, including, without limitation, the obligations pursuant to Section 7.3 "Reclamation Activities". B) Notice of Election. Within thirty (30) days after termination of this Agreement, the Joint Committee will determine fair market value and book value of SJCC's plant, capital equipment and the Coal Leases and other leases in the SJCC Site Area, including all of SJCC's permits and reclamation bonds. The Joint Committee will not disband until it determines such values. Within thirty (30) days after receipt of the Joint Committee determination of value, the Utilities shall notify SJCC in writing which of the above three options the Utilities elect. In the event the Utilities elect the option identified in Section 12.5(A)(1), SJCC shall, within thirty (30) days after written notice of said election, deliver to Utilities a sufficient bill of sale or other appropriate instrument of conveyance, together with an invoice showing in reasonable detail the amount due, whereupon Utilities shall, within sixty (60) days thereafter, remit to SJCC the amount due. In the event Utilities shall elect the option identified in Section 12.5(A)(2), SJCC shall undertake to promptly dispose of its plant and capital equipment, and interest in the Coal Leases and other leases in the SJCC Site Area, including all of SJCC's permits and reclamation bonds, and shall thereafter invoice Utilities for the amount due SJCC (said invoice to show in reasonable detail the amount, if any, received as a result of said disposition, SJCC's book cost (net of depreciation) and the balance due), whereupon Utilities shall, within sixty (60) days after receipt of said invoice, remit to SJCC the amount due SJCC. 44 C) Terms of Transfer. Any transfer of all of SJCC's rights, title and interest in and to the Coal Leases and other leases in the SJCC Site Area, including all of SJCC's permits and reclamation bonds shall be by an appropriate instrument of conveyance, with special warranty covenants, subject to necessary consents, and such assignment and/or transfer will become effective at the earliest possible time after the termination of this Agreement or extension thereof. D) Liabilities Upon Termination. Upon termination the Utilities shall assume all financial obligations, if any, attributable to 1) The then remaining term of the Cimarron Coal Assignment; and, 2) All leases and subleases that are Coal Leases and other leases in the SJCC Site Area as of August 30, 2000 (including private royalty obligations or retained interests). In addition, after termination of this Agreement, the Utilities remain obligated to pay for all surface reclamation associated with disturbance on the SJCC Site Area resulting in any way from the supply of coal to the San Juan Station prior to termination of this Agreement (including reclamation of surface mining and the surface effects of underground mining) and related liabilities, obligations and costs. 12.6 Expiration. A) In the event the Parties fail to agree to extend this Agreement pursuant to Section 2.5 "Extension", the Parties have the obligation to negotiate diligently and in good faith with a view to concluding a new agreement for the purchase and sale of coal to be effective commencing at the expiration of this Agreement. B) Upon expiration as provided in Section 2 "Obligations of the Parties and Term of Agreement", and in the event the Parties have not reached agreement pursuant to Section 12.6(A), the Utilities may elect one of the options identified in Section 12.5(A)(1), Section 12.5(A)(2) and Section 12.5(A)(3). C) Notice of Election. Within thirty (30) days after expiration of this Agreement, the Joint Committee will determine fair market value and book value of SJCC's plant, capital equipment and the Coal Leases and other leases in the SJCC Site Area, including all of SJCC's permits and reclamation bonds. The Joint Committee will not disband until it determines such values. Within thirty (30) days after receipt of the Joint Committee determination of value, the Utilities shall notify SJCC in writing which of the above three options the Utilities elect. In the event the Utilities elect the option identified in Section 12.5(A)(1), SJCC shall, within thirty (30) days after written notice of said election, deliver to Utilities a sufficient bill of sale or other appropriate instrument of conveyance, together with an invoice showing in reasonable 45 detail the amount due, whereupon Utilities shall, within sixty (60) days thereafter, remit to SJCC the amount due. In the event Utilities shall elect the option identified in Section 12.5(A)(2), SJCC shall undertake to promptly dispose of its plant and capital equipment, and interest in the Coal Leases and other leases in the SJCC Site Area, including all of SJCC's permits and reclamation bonds, and shall thereafter invoice Utilities for the amount due SJCC (said invoice to show in reasonable detail the amount, if any, received as a result of said disposition, SJCC's book cost (net of depreciation) and the balance due), whereupon Utilities shall, within sixty (60) days after receipt of said invoice, remit to SJCC the amount due SJCC. D) Terms of Transfer and Liabilities Upon Expiration. Any transfer of all of SJCC's rights, title and interest in and to the Coal Leases and other leases in the SJCC Site Area, including all of SJCC's permits and reclamation bonds, shall be by an appropriate instrument of conveyance, with special warranty covenants, subject to necessary consents, and such assignment and/or transfer will become effective at the earliest possible time after the expiration of this Agreement or extension thereof. After expiration of this Agreement, the Utilities remain obligated to pay for all reclamation and related liabilities, obligations and costs pursuant to Section 7.3 "Reclamation Activities". 46 Section 13 - Indemnity ---------------------- 13.1 Indemnity SJCC shall indemnify and save Utilities harmless from and shall defend them against any and all claims, demands or liabilities arising out of the operations of SJCC under this Agreement at the San Juan Station site or the SJCC Site Area, excepting those specified in Exhibit "F" "Operating Costs", and those claims, demands or liabilities arising out of the acts of Utilities, their employees, agents, contractors, and representatives. Utilities shall indemnify and save SJCC harmless from and defend it against any and all claims, demands or liabilities arising out of the operations of Utilities under this Agreement at the San Juan Station site or the SJCC Site Area, excepting those claims, demands or liabilities arising out of the acts of SJCC, its employees, agents, contractors and representatives. If a court of competent jurisdiction determines that the provisions of ss.56-7-1 or 2, N.M.S.A. (1978 Comp.), are applicable to this Agreement, then only to the extent that any indemnity agreement or any portion of an indemnity agreement contained herein would be deemed void or unenforceable under said provision(s), then to the narrowest extent possible, that portion of the agreement shall not extend to indemnify against liability, claims, damages, losses or expenses, including attorneys' fees, for or arising out of: A) In the case that ss56-7-1, N.M.S.A. (1978 Comp.), is so determined to be applicable, 1) the preparation or approval of maps, drawings, opinions, reports, surveys, change orders, designs or specifications by the indemnified party or the agents or employees of the indemnified party; or 2) the giving of or the failure to give directions or instructions by the indemnified party, or the agents or employees of the indemnified party, where such giving or failure to give directions or instructions is the primary cause of bodily injury to persons or damage to property; and, B) In the case that ss56-7-2, N.M.S.A. (1978 Comp.), is so determined to be applicable, 1) the sole or concurrent negligence of the indemnified party or the agents or employees of the indemnified party or any independent contractor who is directly responsible to the indemnified party; or 2) any accident which occurs in operations carried on at the direction or under the supervision of the indemnified party or an employee or representative of the indemnified party or in accordance with methods and means specified by the indemnified party or employees or representatives of the indemnified party. 47 Section 14 - General Provisions ------------------------------- 14.1 Compliance with Applicable Laws SJCC shall conduct all of its operations under this Agreement in full compliance with all applicable laws, ordinances, regulations and directives of any and all governmental authorities having jurisdiction over such operations in conformity with the provisions of all licenses, permits and approvals; provided, however, that nothing herein shall be construed as prohibiting SJCC from contesting any such law, ordinance, regulation or directive or the provisions of any such license, permit or approval by appropriate judicial or administrative proceedings. 14.2 Labor Force A) SJCC shall comply with the requirements of all civil rights statutes and other federal and state employment laws which may be applicable to its operations under this Agreement. B) Except for any preferential treatment which may be accorded Native American Indians (which treatment shall not violate SJCC's obligations under Section 14.2(A), during the performance of this contract SJCC agrees as follows: 1) SJCC will not discriminate against any employee or applicant for employment because of race, color, religion, sex or national origin. SJCC will take affirmative action to ensure that applicants are employed, and that employees are treated during employment, without regard to their race, color, religion, sex or national origin. Such action shall include, but not be limited to, the following: employment; upgrading; demotion or transfer; recruitment or recruitment advertising; layoff or termination; rates of pay or other forms of compensation; and selection for training, including apprenticeship. SJCC agrees to post in conspicuous places, available to employees and applicants for employment, notices to be provided by the contracting officer setting forth the provisions of this nondiscrimination clause. 2) SJCC will, in all solicitations or advertisements for employees placed by or on behalf of SJCC, state that all qualified applicants will receive consideration for employment without regard to race, color, religion, sex or national origin. 3) SJCC will send to each labor union or representative of workers with which it has a collective bargaining agreement or other contract or understanding, a notice to be provided by the agency contracting officer, advising the labor union or workers' representative of SJCC's commitments under Section 202 of Executive Order No. 11246 of September 24, 1965, and shall post copies of the notice in conspicuous places available to employees and applicants for employment. 48 4) SJCC will comply with all provisions of Executive Order No. 11246 of September 24, 1965, and of the rules, regulations and relevant orders of the Secretary of Labor. 5) SJCC will furnish all information and reports required by Executive Order No. 11246 of September 24, 1965, and by the rules, regulations and orders of the Secretary of Labor, or pursuant thereto, and will permit access to its books, records and accounts by the Secretary of Labor for purposes of investigation to ascertain compliance with such rules, regulations and orders. 6) In the event of SJCC's noncompliance with the nondiscrimination clauses of this contract or with any of the said rules, regulations or order, this contract may be canceled, terminated or suspended, in whole or in part, and SJCC may be declared ineligible for further Government contracts in accordance with procedures authorized in Executive Order No. 11246 of Sept. 24, 1965, and such other sanctions may be imposed and remedies invoked as provided in Executive Order No. 11246 of September 24, 1965, or by rule, regulation or order of the Secretary of Labor, or as otherwise provided by law. 7) SJCC will include the provisions of Sections 14.2 (B)(1) through (7) in every subcontract or purchase order unless exempted by rules, regulations or orders of the Secretary of Labor issued pursuant to Section 204 of Executive Order No. 11246 of September 24, 1965, so that such provisions will be binding upon each subcontractor or vendor. SJCC will take such action with respect to any subcontract or purchase order as may be directed by the Secretary of Labor as a means of enforcing such provisions, including sanctions for noncompliance; provided, however, that in the event SJCC becomes involved in, or is threatened with, litigation with a subcontractor or vendor as a result of such direction, SJCC may request the United States to enter into such litigation to protect the interest of the United States. C) The Parties agree to the extent authorized by law that no party will seek an independent contractual remedy based upon Section 14.2(B)(6) of this Agreement unless such remedy is necessary to effectuate a party's compliance with Federal law or applicable regulations. The Parties acknowledge that this Section 14.2(C) is not intended to conflict with Federal law or limit enforcement authority of the Secretary of Labor or other governmental authority. If this Section 14.2(C) is ever legally determined to violate or conflict with Executive Order No. 11246 of September 24, 1965, its implementing regulations, or other Federal laws or regulations, then this Section 14.2 (C) will be of no force and effect, and will be severed from this Agreement, and, the remainder of the Agreement will be treated pursuant to Section 14.17 "Severability". 49 14.3 Confidentiality / Non-disclosure The terms and conditions, including those dealing with compensation, set forth in this Agreement are considered by Utilities and SJCC to be confidential and proprietary information and none of the Parties shall disclose any such information to any third party other than the attorneys, auditors and agents of Utilities, other owners of the San Juan Station, and SJCC, without the advance written consent of the other Parties; provided, however, disclosure may be made without advance consent where, in the opinion of counsel, such disclosure may be required by order of court or regulatory agency, law or regulation or in connection with judicial or administrative proceedings involving a party hereto, in which event the party to make such disclosure shall advise the other in advance as soon as possible and cooperate to the maximum extent practicable to minimize the disclosure of any such information (including, where practicable, deletion of portions of this Agreement, and, specifically, Section 8 "SJCC Compensation"). Utilities shall maintain with the owners of the San Juan Station other than the Utilities written confidentiality agreements that are acceptable to SJCC prior to the disclosure of the terms of this Agreement. 14.4 The Utilities' Duties and Obligations Shall be Joint and Several The Utilities' duties and obligations under this Agreement shall be joint and several. 14.5 Permits and Approvals SJCC will use its best efforts to acquire any and all permits, licenses and approvals required by any governmental agency or regulatory body to enable SJCC to carry on the operations contemplated by this Agreement, including but without limitation, permits under the "Surface Mining Control and Reclamation Act of 1977" (Pub.L. 95-87, August 3, 1977); provided however, that Utilities will cooperate fully with SJCC and supply information necessary to obtain all permits, licenses and approvals. 14.6 Waivers A waiver by a party at any time of its rights with respect to a default under this Agreement, or with respect to any other matter in connection with this Agreement, shall not be deemed a waiver with respect to any other subsequent default or matter. No delay, short of the statutory period of limitation, in asserting or enforcing any right hereunder shall be deemed a waiver of or limitation on such right. 14.7 Insurance SJCC and Utilities, for the benefit of the other, shall take out and maintain in force during the term of this Agreement the insurance described below covering their operations in respect of which this Section 14.7 applies. The Parties shall insure with one or more insurance companies satisfactory to the other or self insure by means of a self insurance program acceptable to the other, and each party shall submit to the other satisfactory evidence of said insurance or self insurance. Said insurance shall not be cancelled or materially changed with less than thirty (30) days prior written notice to the other party hereto and the certificates shall so provide. The insurance required is the following: 50 A) Workmen's Compensation and Employer's Liability Insurance as required under applicable law, including, as appropriate, obligation to provide Black Lung disease benefits under the Federal Coal Mine Health and Safety Act. B) Automobile Liability Insurance, or the equivalent, covering claims from third parties arising from the operation of automobiles. C) Property Insurance providing all risk replacement cost coverage for real and personal property damage, including damage to equipment. D) Commercial General Liability Insurance, or the equivalent, (including blanket contractual liability coverage with respect to this Agreement) including defense costs for claims for damages to third parties because of bodily injury, property damage, personal and advertising injury, including products and completed operations. E) Umbrella and /or Excess Liability Insurance, or the equivalent, including claims in excess of scheduled underlying policies. F) Fidelity Insurance, or the equivalent, covering loss arising out of fraudulent or dishonest acts of employees. G) ERISA Fidelity, or the equivalent, covering loss arising out of fraudulent or dishonest acts of employees related to retirement plans as required by ERISA. H) Fiduciary Liability Insurance, or the equivalent, covering claims arising from wrongful acts. It shall be the responsibility of the Joint Committee to review the insurance coverage before July 31, 2003, and then no less often than every five (5) years thereafter, and to determine adequate limits and coverages for the then current conditions. 14.8 Notices A) Any notice, demand or request provided for in this Agreement, or given or made in connection with this Agreement, except those normal exchanges of information required by the Coordinating Committee and the Joint Committee, shall be in writing, signed by an officer of the party giving such notice and shall be deemed to be properly and sufficiently given or made if sent by registered or certified mail, and if to SJCC, addressed as follows: San Juan Coal Company 300 West Arrington, Suite 200 Farmington NM, 87401 Attention: President with a copy addressed as follows: 51 San Juan Coal Company Post Office Box 155 Fruitland, NM 87416 Attention: San Juan Mine Manager and if to Utilities, addressed as follows: Public Service Company of New Mexico Alvarado Square Albuquerque, NM 87158 Attention: Corporate Secretary and Tucson Electric Power Company Post Office Box 711 Tucson, AZ 85702 Attention: Secretary B) Any party hereto may change its address for notice by so advising the other Parties hereto in accordance with the provisions of this Section 14.8. Any notice given in accordance with the provisions of this Section 14.8 shall be deemed effectively given as of the date of its deposit with the United States Postal Service. C) Exchanges of information required by the Coordinating Committee and the Joint Committee shall be by procedures set forth by the respective committee. 14.9 Choice of Law The terms and provisions of this Agreement shall be interpreted and construed in accordance with the laws of the State of New Mexico, without regard to conflict of law principles. 14.10 Assignment A) This Agreement may not be assigned or subcontracted by SJCC without the consent of Utilities, except that no consent shall be required in event of an assignment of amounts receivable hereunder to a bank or lending institution, or a collateral assignment for purposes of securing indebtedness, or a transfer under or pursuant to a mortgage, deed of trust or indenture (including, without limitation, a transfer by foreclosure or a sale under the power of sale contained in any such mortgage, deed of trust or indenture), or a transfer to a successor in interest, by merger, consolidation, sale and transfer, or otherwise, acquiring all or substantially all of the assets and business of SJCC, and except for transfer to a subsidiary as herein below provided; provided, however, that any assignee, successor in interest or transferee hereunder shall first guarantee performance of this Agreement in a manner satisfactory to Utilities. B) This Agreement may not be assigned by Utilities without the consent of SJCC, except that no consent shall be required in event of an assignment or transfer under and pursuant to a 52 mortgage, deed of trust or indenture (including, without limitation, a transfer by foreclosure or a sale under the power of sale contained in any such mortgage, deed of trust or indenture), or an assignment to a successor in interest, by merger, consolidation, sale and transfer, or otherwise, acquiring all or substantially all of the business and assets of any of the Utilities and except for transfer to a subsidiary as herein below provided; provided, however, that any assignee, successor in interest or transferee hereunder shall first guarantee performance of this Agreement in a manner satisfactory to SJCC. C) Any party hereto may without the consent of any other party, assign this Agreement to a majority-owned subsidiary corporation or to a wholly-owned subsidiary of its parent provided that the assigning party shall guarantee performance of this Agreement by such subsidiary. D) Consent to assignment hereunder shall not be unreasonably withheld by any party hereto. 14.11 Successors and Assigns Subject to Section 14.10 "Assignment", this Agreement and all of the obligations and rights herein established shall extend to and be binding upon, and shall inure to the benefit of, the respective successors and assigns of the respective Parties. 14.12 Authorizations The execution and performance by the Parties of this Agreement have been duly authorized for each party by all necessary corporate action, require no other authorization, consent or approval and do not contravene any law or contractual restriction binding on the Parties. 14.13 Amendments This Agreement may be amended only by written instrument executed by all of the Parties with the same formality as this Agreement. 14.14 Construction The terms and conditions of this Agreement are the result of negotiation and drafting on an equal footing by the Parties and their legal counsel. This Agreement shall be construed evenhandedly and without favor or predisposition to any party. The titles of sections in this Agreement have been inserted as a matter of convenience or for reference only, and they shall not control or affect the meaning or construction of any of the terms and provisions hereof. 14.15 Entire Agreement This Agreement supersedes all prior agreements and representations between the Parties, whether written or oral, with respect to the subject matter of this Agreement and is intended as a complete and exclusive statement of the terms of the agreement between the Parties with respect to the subject matter. Except as specifically set forth in this Agreement, no representations have been made to induce any of the Parties to enter into this Agreement. All Exhibits are incorporated by reference as part of this Agreement. 53 14.16 Waiver of Consequential Damages. SJCC and the Utilities waive any recovery of consequential damages related to the breach of this Agreement. 14.17 Severability In the event that any of the terms or conditions of this Agreement, or the application of any such term or condition to any person or circumstance, shall be held invalid by an arbitration panel constituted under this Agreement or any court having jurisdiction in the premises, the remainder of this Agreement, and the application of such terms or conditions to persons or circumstances other than those as to which it is held invalid, shall not be affected thereby, except that the provisions in the remainder of this Agreement shall be construed, and modified where necessary, to effectuate the intentions of the Parties and provide them with the benefit of their bargain. 14.18 Survival of Provisions The Parties agree that those provisions that describe the Parties' post-expiration and post-termination rights and obligations shall survive termination or expiration of this Agreement. In addition, those provisions and Exhibits referenced in, or necessary to implement, the provisions that describe the Parties' post-termination or post-expiration rights and obligations also shall survive. 54 Section 15 - Signatures ----------------------- IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed on their behalf by their respective officers, thereunto duly authorized. PUBLIC SERVICE COMPANY OF NEW MEXICO By: /s/ Patrick J. Goodman. 8/29/01 ---------------------------------------- ------- Patrick J. Goodman, Vice President Date TUCSON ELECTRIC POWER COMPANY By: /s/ Kevin Larson....... 8/31/01 ------------------------------------------------- ------- Kevin Larson, Vice President Date SAN JUAN COAL COMPANY By: /s/ John W. Grubb...... 8/29/01 ---------------------------------------- ------- John W. Grubb, President Date 55 EX-15 8 exh15.txt EXHIBIT 15.0 Public Service Company of New Mexico Alvarado Square Albuquerque, New Mexico 87158 November 13, 2001 Public Service Company of New Mexico: We are aware that PUBLIC SERVICE COMPANY OF NEW MEXICO and subsidiaries has incorporated by reference in its Registration Statement No. 33-65418, 333-03289, 333-03303, 333-32170 and 333-53367 its Form 10-Q for the quarter ended September 30, 2001, which includes our report dated November 9, 2001 covering the unaudited interim financial information contained therein. Pursuant to Regulation C of the Securities Act of 1933, that report is not considered a part of the registration statement prepared or certified by our firm or a report prepared or certified by our firm within the meaning of Sections 7 and 11 of the Act. Very truly yours, Arthur Andersen LLP -----END PRIVACY-ENHANCED MESSAGE-----