-----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, H08TKBQG902J6Zwternr9tZNq8mWZTZwVDjoxSo2mJG7noDxnraz56JCEqnVm5Nn TSGb51nP4FG0/v4ECUqAeQ== 0001108426-02-000015.txt : 20020415 0001108426-02-000015.hdr.sgml : 20020415 ACCESSION NUMBER: 0001108426-02-000015 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 7 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020326 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-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-06986 FILM NUMBER: 02586914 BUSINESS ADDRESS: STREET 1: ALVARADO SQUARE, MS2706 CITY: ALBUQUERQUE STATE: NM ZIP: 87158 BUSINESS PHONE: 5058482700 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PNM RESOURCES CENTRAL INDEX KEY: 0001108426 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 850468296 STATE OF INCORPORATION: NM FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 333-32170 FILM NUMBER: 02586913 BUSINESS ADDRESS: STREET 1: ALVARADO SQUARE STREET 2: NEW MEXICO CITY: ALBUQUERQUE STATE: NM ZIP: 87158 BUSINESS PHONE: 5052412700 MAIL ADDRESS: STREET 1: ALVARADO SQUARE CITY: ALBUQUERQUE STATE: NM ZIP: 87158 FORMER COMPANY: FORMER CONFORMED NAME: MANZANO CORP DATE OF NAME CHANGE: 20000303 10-K 1 f10k_2001pnmr.txt 2001 10-K COMBINED FILING OF PNMR AND PNM ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------------------- FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended December 31, 2001 Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address and Telephone Number Identification No. ----------- ---------------------------- ------------------ 333-32170 PNM Resources, Inc. 85-0468296 (A New Mexico Corporation) Alvarado Square Albuquerque, New Mexico 87158 (505) 241-2700 1-6986 Public Service Company of New Mexico 85-0019030 (A New Mexico Corporation) Alvarado Square Albuquerque, New Mexico 87158 (505) 241-2700 Securities Registered Pursuant To Section 12(b) Of The Act: Name of Each Exchange Registrant Title of Each Class on Which Registered - ---------- ------------------- --------------------- PNM Resources, Inc. Common Stock, No Par Value New York Stock Exchange Securities Registered Pursuant To Section 12(g) Of The Act: Registrant Title of Each Class - ---------- ------------------- Public Service Company 1965 Series, 4.58% Cumulative Preferred Stock of New Mexico ($100 stated value without sinking fund) Indicate by check mark whether each 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 Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X| The total number of shares of Common Stock of PNM Resources, Inc. ("PNM Resources") outstanding as of January 31, 2002 was 39,117,799. On such date, the aggregate market value of the voting stock held by non-affiliates of PNM Resources, as computed by reference to the New York Stock Exchange composite transaction closing price of $27.01 per share reported by The Wall Street Journal, was $1,056,571,751. DOCUMENTS INCORPORATED BY REFERENCE Portions of the following document are incorporated by reference into the indicated part of this report: Proxy Statement to be filed by PNM Resources with the Securities and Exchange Commission pursuant to Regulation 14A relating to the annual meeting of stockholders of PNM Resources to be held on May 14, 2002 - PART III. This combined Form 10-K represents separate filings by PNM Resources and PNM. Information combined herein relating to an individual registrant is filed by that registrant on its own behalf. PNM makes no representations as to the information relating to PNM Resources and its subsidiaries other than PNM. When this combined Form 10-K is incorporated by reference into any filing with the SEC made by PNM, the portions of this Form 10-K that relate to PNM Resources and its subsidiaries other than PNM are not incorporated by reference therein. ii TABLE OF CONTENTS Page ---- GLOSSARY................................................................... v PART I ITEM 1. BUSINESS.......................................................... 1 THE COMPANY.................................................. 1 UTILITY OPERATIONS........................................... 2 Electric Services........................................ 2 Gas Services............................................. 3 GENERATION AND TRADING OPERATIONS............................ 4 Power Sales............................................... 4 Sources of Power......................................... 5 Fuel and Water Supply.................................... 6 UNREGULATED OPERATIONS....................................... 8 RATES AND REGULATION......................................... 9 Electric Rates and Regulation............................ 10 Gas Rates and Regulation................................. 11 ENVIRONMENTAL MATTERS........................................ 12 COMPETITION.................................................. 15 EMPLOYEES.................................................... 16 ITEM 2. PROPERTIES........................................................ 16 ELECTRIC..................................................... 16 Fossil-Fueled Plants..................................... 17 Nuclear Plant............................................ 17 Other Electric Properties................................ 22 NATURAL GAS.................................................. 22 OTHER INFORMATION............................................ 22 ITEM 3. LEGAL PROCEEDINGS................................................. 23 PVNGS Water Supply Litigation............................. 23 San Juan River Adjudication............................... 23 Republic Savings Bank Litigation.......................... 23 Purported Navajo Environmental Regulation................. 24 Royalty Claims............................................ 24 KAFB Contract............................................. 25 Avistar Severence......................................... 26 Western Resources......................................... 27 Reeves Station Environmental Matters...................... 28 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............... 29 SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF THE COMPANY....................... 29 iii PART II ITEM 5. MARKET FOR THE COMPANY'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS............................... 32 ITEM 6. SELECTED FINANCIAL DATA......................................... 33 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS....................... 34 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.......................................... 74 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................... F-1 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE........................ E-1 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY................. E-1 ITEM 11. EXECUTIVE COMPENSATION.......................................... E-1 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS E-1 AND MANAGEMENT............................................. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................. E-1 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K................................................ E-1 SIGNATURES.................................................................E-28 iv GLOSSARY Act.......................... The Clean Air Act - Amendments of 1990 Afton........................ Afton Generating Station Avistar...................... Avistar, Inc., an unregulated subsidiary of PNM Resources, Inc. AG........................... New Mexico Attorney General AMDAX........................ AMDAX.com, an equity investee of Avistar Anaheim...................... City of Anaheim, California APPA......................... Arizona Power Pooling Association APS.......................... Arizona Public Service Company BHP.......................... BHP Holdings (Operations) BLM.......................... Bureau of Land Management BNCC......................... BHP Navajo Coal Company BTU.......................... British Thermal Unit COA.......................... City of Albuquerque, New Mexico Decatherm.................... 1,000,000 BTUs Delta........................ Delta-Person Limited Partnership, a New Mexico limited partnership DOE.......................... United States Department of Energy EIP.......................... Eastern Interconnection Project El Paso...................... El Paso Electric Company EPA.......................... United States Environmental Protection Agency EPNG......................... El Paso Natural Gas Company FASB......................... Financial Accounting Standards Board Farmington................... City of Farmington, New Mexico FERC......................... Federal Energy Regulatory Commission FIP.......................... Federal Implementation Plan Four Corners................. Four Corners Power Plant FPPCAC....................... Fuel and Purchased Power Cost Adjustment Clause Gallup....................... City of Gallup, New Mexico Gathering Company............ Sunterra Gas Gathering Company, a wholly-owned subsidiary of PNM Resources, Inc ISO.......................... Independent System Operator KAFB......................... Kirtland Air Force Base Kv........................... Kilovolt KW........................... Kilowatt KWh.......................... Kilowatt Hour Lordsburg.................... Lordsburg Generating Station Los Alamos................... The County of Los Alamos, New Mexico mcf.......................... Thousand cubic feet Meadows...................... Meadows Resources, Inc., a wholly-owned subsidiary of Public Service Company of New Mexico M-S-R........................ M-S-R Public Power Agency, a California public power agency MW........................... Megawatt MWh.......................... Megawatt Hour NMED......................... New Mexico Environment Department v NMPUC........................ New Mexico Public Utility Commission NRC.......................... United States Nuclear Regulatory Commission NSPS......................... New Source Performance Standards NSR.......................... New Source Review OCD.......................... New Mexico Oil Conservation Division PGAC......................... The Company's Purchased Gas Adjustment Clause PG&E......................... Pacific Gas and Electric Co. PLP.......................... Cobisa-Person Limited Partnership PPA.......................... Power Purchase Agreement PRC.......................... New Mexico Public Regulation Commission, successor of the NMPUC Processing Company........... Sunterra Gas Processing Company, a wholly-owned subsidiary of PNM Resources, Inc. PSD.......................... Prevention of Significance Determination PVNGS........................ Palo Verde Nuclear Generating Station RCRA......................... Resource Conservation and Recovery Act RHC.......................... Republic Holding Company RSB.......................... Republic Savings Bank RTO.......................... Regional Transmission Organization Reeves Station............... Reeves Generating Station Salt River Project........... Salt River Project Agricultural Improvement and Power District SCE.......................... Southern California Edison Company SCPPA........................ Southern California Public Power Authority SDG&E........................ San Diego Gas and Electric Company SEC.......................... Securities and Exchange Commission SJCC......................... San Juan Coal Company SJGS......................... San Juan Generating Station SPS.......................... Southwestern Public Service Company TNP.......................... Texas-New Mexico Power Company Throughput................... Volumes of gas delivered, whether or not owned by the Company Tri-State.................... Tri-State Generation and Transmission Association, Inc. Tucson....................... Tucson Electric Power Company UAMPS........................ Utah Associated Municipal Power Systems USBR......................... United States Bureau of Reclamation USEC......................... United States Enrichment Corporation WGA.......................... Western Governors Association WRAP......................... Western Regional Air Partnership Waste Act.................... Nuclear Waste Policy Act of 1982, as amended in 1987 WAPA......................... Western Area Power Administration Williams..................... Williams Gas Processing-Blanco, Inc., a subsidiary of the Williams Field Services Group, Inc., of Tulsa, Oklahoma vi PART I ITEM 1. BUSINESS THE COMPANY PNM Resources, Inc. (the "Company") was incorporated in the State of New Mexico on March 3, 2000. PNM Resources' principal subsidiary Public Service Company of New Mexico ("PNM") was incorporated in the State of New Mexico on May 9, 1917. The Company has its principal offices at Alvarado Square, Albuquerque, New Mexico 87158 (telephone number 505-241-2700). The Company is a holding company of energy and energy-related companies. Its principal subsidiary is a public utility primarily engaged in the generation, transmission, distribution, sale and trading of electricity, and in the transmission, distribution and sale of natural gas within the State of New Mexico. Upon the completion on December 31, 2001, of a one-for-one share exchange between PNM and the Company, the Company became the parent company of PNM. Prior to the share exchange, the Company had existed as a subsidiary of PNM. The new holding company began trading on the New York Stock Exchange under the same PNM symbol beginning on December 31, 2001. This filing for the Company and PNM is presented on a combined basis. The Company as an unconsolidated holding company ("Holding Company") had no material operations for the year ended December 31, 2001. Except for its consolidated investment in PNM, the Holding Company's only assets were cash of $11 million, short-term investments of $10 million and long-term investments of $106 million at December 31, 2001. In addition, the Holding Company had no liabilities at December 31, 2001. Accordingly, the reader should assume that the information presented applies to both the Company and PNM, except where the context or references clearly indicate otherwise. The Company operates as three distinct business units: (1) Utility Operations, (2) Generation and Trading Operations and (3) Unregulated Operations. Utility Operations and Generation and Trading Operations are business units of Public Service Company of New Mexico. Utility Operations include the Electric Services ("Electric") and the Gas Services ("Gas"). Electric consists of the distribution of electricity, as well as all activities related to the Company's electric transmission operations. Gas includes the transportation and distribution of natural gas to end-users. The Generation and Trading Operations include all production and purchase of energy, the sale of wholesale energy to Utility Operations and third parties, as well as energy trading activities. Unregulated Operations provide energy related services. On January 11, 2002, the Company's primary subsidiary engaged in unregulated activities, Avistar, was dividended to the Company by its subsidiary, Public Service Company of New Mexico. Financial information relating to amounts of sales, revenue, net income and total assets of the Company's business units or reportable segments is contained in Part II, Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" or note 1 of the notes to consolidated financial statements. 1 UTILITY OPERATIONS Electric The Company provides jurisdictional retail electric service to a large area of north central New Mexico, including the COA and the City of Santa Fe, and certain other areas of New Mexico. The largest retail electric customer served by the Company accounted for approximately 4.2% of the Company's total retail electric revenues for the year ended December 31, 2001. For the years 1997 through 2001, retail KWh sales have grown at a compound annual rate of approximately 2.65%. The Company's system peak demands for its retail customers and firm requirements customers in summer and winter for the last three years are shown in the following table: SYSTEM PEAK DEMAND (Megawatts) 2001 2000 1999 --------- --------- --------- Summer....................... 1,397 1,368 1,291 Winter....................... 1,294 1,211 1,161 The Company holds long-term, non-exclusive franchise agreements for its electric retail operations, expiring between June 2002 and November 2028. These franchise agreements provide the Company access to public rights-of-way for placement of the Company's electric facilities. The COA, City of Santa Fe, Town of Cochiti Lake, Bernalillo County, Luna County, Sandoval County, San Miguel County, Village of Bosque Farms and Village of Tijeras franchises have expired. The COA metropolitan area accounted for approximately 52% of the Company's 2001 total electric utility operating revenues, and no other franchise area represents more than approximately 8%. The Company continues to collect and pay franchise fees to the COA, City of Santa Fe, the Town of Cochiti Lake, Village of Bosque Forms and Village of Tijeras. The Company currently does not pay franchise fees to Bernalillo County, Luna County, Sandoval County and San Miguel County. The Company remains obligated under state law to provide service to customers in the franchise area even in the absence of a franchise agreement. 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 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. The Company owns or leases 2,890 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. Due to rapid load growth in the Company's service territory in recent years and the lack of transmission development, most of the capacity on this transmission system is fully committed and there is very little or no additional access available on a firm commitment basis. These factors result in physical constraints in the system and limit the ability to wheel power into the Company's service area from outside the state. 2 Gas The Company's Gas operations distribute natural gas to most of the major communities in New Mexico, including the COA and the City of Santa Fe. The COA metropolitan area accounted for approximately 33% of the total gas revenues. No single sales-service customer accounted for more than approximately 4% of the Company's therm sales in 2001. The Company holds long-term, non-exclusive franchises with varying expiration dates in all incorporated communities requiring franchise agreements except for the COA, City of Santa Fe, Aztec, Village of Bosque Farms, Town of Cochiti Lake, Los Ranchos de Albuquerque and Tatum. The Company remains obligated to serve the franchise areas pursuant to state law even in the absence of a franchise agreement. The Company's 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. Cost-of-gas revenues collected from on-system sales-service customers are recovered in accordance with PRC regulations and represent a pass-through of the Company's cost of natural gas to the customer. Since the Company obtains its natural gas supply on the open market from non-affiliated third-party producers, the Company's operating results are not affected by an increase or decrease in natural gas prices. 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. Transportation services are provided to gas marketers, producers and end users for delivery to locations throughout the Company's distribution systems, as well as for delivery to interstate pipelines. The Company provided gas transportation deliveries to approximately 1,360 gas marketers, producers and end users during 2001. During 2001, approximately 52% of the Company's total gas throughput was related to transportation gas deliveries. The Company's transportation rates are unbundled, and transportation customers only pay for the service they receive. Cost-of-gas revenues, received from sales-service and off-system customers, and other PGAC-related revenues accounted for approximately 65% of the Company's total gas operating revenues in 2001. Since a major portion of the Company's load is related to heating, levels of therm sales are affected by weather. Approximately 54% of the Company's total therm sales in 2001 occurred in the months of January, February, November and December. The Company obtains its supply of natural gas primarily from sources within New Mexico pursuant to contracts with third party 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. Such transportation is regulated by FERC. As a result of FERC Order 636, the Company's options for transporting gas to such cities and other portions of its distribution system have increased. 3 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. Intersegment sales to the Utility Operations are priced using internally developed transfer pricing and are not based on market rates. 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 energy sales from excess capacity 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. These sales include the Company's wholesale power trading activities. The Company is connected to the Western area power grid, which includes California and the surrounding states, and therefore its wholesale power sales are into this market. The Western United States power market in 2000 and 2001 was, and continues to be, extremely volatile due to a power supply shortage and other constraints associated with the Western United States electricity market. (See Part II, Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations - Other issues facing the Company - Western United States Wholesale Power Market.) Power Sales A significant portion of the Company's earnings is derived from its off-system sales. The Company has been very successful in developing its wholesale power trading activities in the Western United States. Management believes this success is due to its niche business strategy of providing electric power customized to meet the special needs of customers. This niche marketing strategy is based on the Company's asset-backed trading methodology whereby the Company's net open position is always supported by its generation capacity excluded from its jurisdictional rates, or by its jurisdictional excess capacity. This asset-backed trading methodology helps to mitigate the risks inherent in the Company's trading activities. The Company also utilizes long-term transactions to enhance its product offering. Certain of the Company's generation assets are excluded from jurisdictional electric rates. In 1988, the NMPUC excluded 130MW of SJGS Unit 4 and all of PVNGS Unit 3. As a result, the Company developed a bulk power marketing and trading operation to sell the generation from its excluded assets that no longer generated a return in rate base. These activities include the forward purchase and sale of electricity to take advantage of market price opportunities in the electric wholesale market. The Company's wholesale power marketing area continues to increase the scope of its trading activities. During 2001, 2000 and 1999, the Company's sales in the off-system markets accounted for approximately 64%, 64% and 62%, respectively, of its total KWh sales. Of the total off-system sales made in 2001 and 2000, 77% and 75% respectively were transacted through purchases for resale. In 1990, the NMPUC established an off-system sales methodology that provided for a sharing mechanism whereby a certain amount of revenues from off-system sales were credited to reduce retail cost of service. Subsequent rate cases continued to utilize this methodology. As a result, electric customers have received over $300 million in rate benefits since 1990 from the Company's 4 wholesale power marketing activities. As of December 31, 1998, the assets included in the electric customer rate base no longer had any excess capacity for purposes of certain portions of the sharing mechanism. The last rate case froze rates until January 1, 2003. A significant portion of the Company's growth strategy is based on growth in off-system sales. The Company's business plan calls for the expansion of its wholesale power trading operation and the acquisition or development of additional generating capacity to support this growth under the Company's asset-backed trading methodology. The Company has committed to purchase five combustion turbines at a total cost of $151.3 million. The plants' estimated cost of construction is approximately $400.3 million of which the Company has expended $103.4 million as of December 31, 2001. In November 2001, the Company broke ground for Afton, a 135 MW gas fired generating plant on a site in Southern New Mexico. This facility is expected to be operational by October 2002. Currently, the Company plans to expand the facility to 225 MW by the end of 2003. In February 2002, the Company also broke ground to build Lordsburg, an 80 MW natural gas fired generating plant in Southwestern New Mexico. This facility is expected to be operational by July 2002. The planned plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. The Company has entered into various firm off-system sales contracts. These contracts contain fixed capacity charges in addition to energy charges. The SDG&E contract, which required SDG&E to purchase 100 MW from the Company expired on April 30, 2001. The APPA contract requires APPA to purchase varying amounts of power from the Company through May 2008 and allows APPA to make adjustments to the purchase amounts subject to certain notice provisions. For 2001, APPA invoked its option to increase its peak demand to 92 MW. The APPA demand will drop to 15 MW in June 2002. The Company furnished firm-requirements wholesale power in New Mexico in 2001 to the City of Gallup. The Company is committed to provide service to the City of Gallup through April 2003. Average monthly demands under the City of Gallup contract for 2001 were approximately 27 MW. Beginning July 2000, the Company began serving Navopache Electric Cooperative firm-requirements service under the provisions of a 10-year contract. Average monthly demand for Navopache is 50 MW. The Company began serving a partial requirements contract with the Texas-New Mexico Power Company in July 2001 for 62 MW. The contract service drops to 32 MW for 2002, then becomes a full requirements contract in January 2003 and continues through 2006. The full requirements demand is expected to be 107 MW in 2003, 109 MW in 2004, 111 MW in 2005 and 114 MW in 2006. No firm requirements wholesale customer accounted for more than 0.01% of the Company's total electric sales for resale revenues for the year ended December 31, 2001. Sources of Power As of December 31, 2001, the total net generation capacity of facilities owned or leased by the Company was 1,521 MW, excluding the PPA discussed below which would bring the total to 1,653 MW. The Company is committed to increasing its utilization of its major generation capacity at SJGS, Four Corners and PVNGS. SJGS is operated by the Company. In 2001, the plant's capacity factor performance ranked in the 90th percentile of the 403 coal-fired power plants in the nation. SJGS's equivalent availability and capacity factor were 84.7% and 82.1% respectively, for the twelve months ended December 31, 2001, as compared to 88.9% and 85.6%, respectively for 2000. Capacity factors for Four Corners and PVNGS were 83.75% and 88.12%, respectively, in 2001, as compared to 84.2% and 92.7%, respectively, in 2000. Four Corners and PVNGS are operated by APS. (See Item 2. Properties). 5 In addition to generation capacity, the Company purchases power in the market. The Company has a power purchase contract with SPS which originally provided for the purchase of up to 200 MW per year and expires in May 2011. The Company may reduce its purchases from SPS by 25 MW annually upon three years notice. The Company provided notice to reduce the purchase by 25 MW in 1999 and by an additional 25 MW in 2000. The Company also is party to a master power purchase and sale agreement with SPS, dated August 2, 1999 pursuant to which the Company has agreed to purchase 72 MW of firm power from SPS from 2002 through 2005. In addition, the Company has 70 MW of contingent capacity obtained from El Paso under a transmission capacity for generation capacity trade arrangement through September 2004. Beginning October 2004 and continuing through June 2005, the capacity amount is 39 MW. The Company holds a PPA with Tri-State for 50 MW through June 30, 2010. In addition, the Company is interconnected with various utilities for economy interchanges and mutual assistance in emergencies. In 1996, the Company entered into a long-term PPA for the rights to all the output of the new Delta gas-fired generating plant for 20 years. The plant has received FERC approval for "exempt wholesale generator" status with respect to the gas turbine generating unit. The PPA's maximum dependable capacity is 132 MW. In July 2000, the plant went into operation. The gas turbine generating unit is operated by Delta and is located on the Company's retired Person Generating Station site in the COA. The site for the generating unit was chosen, in part, to provide needed benefits to the Company's constrained transmission system. Primary fuel for the gas turbine generating unit is natural gas, which is provided by the Company. In addition, the unit has the capability to utilize low sulfur fuel oil in the event natural gas is not available or cost effective. For accounting purposes, the PPA is treated as an operating lease. Fuel and Water Supply The percentages of the Company's generation of electricity (on the basis of KWh) fueled by coal, nuclear fuel and gas and oil, and the average costs to the Company of those fuels (in cents per million BTU), during the past three years were as follows: Coal Nuclear Gas and Oil Percent of Average Percent of Average Percent of Average ---------------------- --------------------- --------------------- 2001...... 66.9 179.6 28.4 45.7 4.7 524.5 2000...... 68.0 165.3 29.8 45.4 2.2 482.6 1999...... 67.6 165.3 31.0 47.4 1.4 331.9 The estimated generation mix for 2002 is 66.8% coal, 29.1% nuclear and 4.2% 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 into the foreseeable future. Coal The coal requirements for the SJGS are being supplied by SJCC, a wholly-owned subsidiary of BHP, who holds certain Federal, state and private coal leases under a Coal Sales Agreement pursuant to which SJCC will supply processed coal for operation of the SJGS until 2017. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the agreement, which contemplates the delivery of approximately 103 million tons of coal during its remaining term. That amount would supply substantially all the requirements of the SJGS through approximately 2017. 6 In August 2001, the Company signed an agreement with SJCC and Tucson to replace two surface mining operations with a single underground mine located adjacent to the plant. Underground mining is expected to provide a higher quality coal at a lower cost per ton. The new mine will use the longwall mining technique and is expected to ramp to full station supply by the end of 2002. The revised coal contract, entered into as a result of the move to an underground mine, is expected to save the Company between $400 million and $500 million in fuel costs over the next 16 years. Besides saving on fuel costs, the cleaner-burning, less abrasive coal is expected to reduce the Company's share of the plant's maintenance and operating expenses. The plant is expected to realize some of the benefits of the higher quality coal in 2002, as the existing surface mines are phased out and the underground mine is developed. Four Corners is supplied with coal under a fuel agreement between the owners and BNCC, under which BNCC agreed to supply all the coal requirements for the life of the plant. The current fuel agreement expires December 31, 2004. Negotiations for an extension have been initiated. BNCC holds a long-term coal mining lease, with options for renewal, from the Navajo Nation and operates a surface mine adjacent to Four Corners with the coal supply expected to be sufficient to supply the units for their estimated useful lives. Natural Gas The natural gas used as fuel for the Company's COA electric generating plant (Reeves Station and the PPA) is delivered by Gas. (See "Gas Services"). 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's Generation and Trading Operations commenced a hedging program to reduce its exposure to fluctuations in prices for natural gas as a fuel source for its generation. (See Note 5 to the Consolidated Financial Statements). Nuclear Fuel The fuel cycle for PVNGS is comprised of the following stages: o the mining and milling of uranium ore to produce uranium concentrates, o the conversion of uranium concentrates to uranium hexafluoride, o the enrichment of uranium hexafluoride, o the fabrication of fuel assemblies, o the utilization of fuel assemblies in reactors, and o the storage and disposal of spent fuel. The PVNGS participants have made contractual arrangements to obtain quantities of uranium concentrates anticipated to be sufficient to meet operational requirements through 2002. Existing uranium concentrates contracts and options could be utilized to meet approximately 67% of requirements in 2003. Spot purchases on the uranium concentrates market will be made, as appropriate. Through the enriched uranium product ("EUP") contract, and through conversion services contracts, the PVNGS participants have arranged for uranium conversion services that will meet 100% of requirements in 2002 and 2003. The PVNGS participants have an enrichment services contract and an EUP contract that furnish enrichment services required for the operation of the three PVNGS units through 2003. 7 The PVNGS participants have a new EUP contract that will furnish up to 100% of PVNGS's requirements for uranium, conversion services and enrichment services from 2004 through 2008. This contract could also provide 100% of enrichment services in 2009 and 2010. In addition, existing contracts will provide 100% of fuel assembly fabrication services until at least 2015 for each PVNGS unit. Water Supply Water for SJGS and Four Corners is obtained from the San Juan River. (See Item 3. - "Legal Proceedings- San Juan River Adjudication".) The Company and Tucson have a contract with the USBR ("USBR Contract") 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 BNCC. The Company is of the opinion that sufficient water is under contract for the SJGS through 2005. BNCC holds rights to San Juan River water and committed a portion of those rights to Four Corners through the life of the plant. In 2000, the Company signed a twenty-two year contract with Jicarilla, beginning in 2006, for the full 16,200 acre feet of water from the Jicarilla supply in Navajo Reservoir ("Jicarilla Contract"). The Jicarilla Contract is essentially equivalent to a renewed USBR Contract, the only material difference being that Jicarilla as opposed to USBR would be the contract supplier. Jicarilla has contract water in Navajo Reservoir pursuant to a water rights settlement approved by Congress in 1992 and a judicial decree that was entered February 24, 1999. The contract has received all requisite approvals. Additionally, the Company has entered into an agreement with the Navajo Nation to settle claims the tribe may assert in connection with any environmental approvals that may be required for a Jicarilla Contract. This settlement with the Navajo Nation will not have a material adverse effect on the Company's financial position or its results of operations. Sewage effluent used for cooling purposes in the operation of the PVNGS units is obtained under contracts with certain municipalities in the area. The contracted quantity of effluent exceeds the amount required for the three PVNGS units. The validity of these effluent contracts is the subject of litigation in state court. (See Item 3. - "Legal Proceedings - PVNGS Water Supply Litigation".) UNREGULATED OPERATIONS 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. 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 operation to the Sangre de Cristo Water Company to the City of Santa Fe was completed in the third quarter of 2001. All remaining non-Reliadigm investments were written-off with the exception of Avistar's investment in Nth Power, an energy related venture capital fund. The Company recorded charges of $13.1 million to reflect these activities and the impairment of its Avistar investments. RATES AND REGULATION PNM is subject to the jurisdiction of the PRC, the successor of the NMPUC effective January 1, 1999, with respect to its retail electric and gas rates, service, accounting, issuance of securities, construction of major new generation and transmission facilities and other matters regarding retail 8 utility services provided in New Mexico. The FERC has jurisdiction over rates and other matters related to wholesale electric sales and cost recovery of its transmission network. In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for corporate separation of supply service and energy-related service assets from distribution and transmission service assets. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The Company is unable to predict the form its further restructuring will take under the delayed implementation of customer choice. In addition, the Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers ("stranded costs"). (See Item 7. "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). 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 Item 7. "Management's Discussion and Analysis of Financial Condition And Results of Operations - Other Issues Facing the Company - Merchant Plant Filing.") On December 31, 2001, the Company implemented the holding company structure without corporate separation of supply service and energy-related services assets from distribution and transmission services assets. This structure provides for a holding company whose current holdings will be Public Service Company of New Mexico, Avistar and other inactive unregulated subsidiaries. This was effected through the share exchange between existing Company shareholders and the holding company, PNM Resources. Avistar and most of the inactive unregulated subsidiaries became wholly-owned subsidiaries of the holding company in January 2002. There are no current plans to provide the holding company with significant debt financing. 9 Because of its ownership of PNM, the Company is a "public utility holding company" under the Public Utility Holding Company Act of 1935 ("PUHCA"). However, the Company is exempt from the provisions of PUHCA, except Section 9(a)(2) thereof, which requires the approval of the SEC for a direct or indirect acquisition by a public utility holding company of five percent or more of the voting securities of any electric or gas utility company subject to PUHCA. Electric Rates and Regulation Proceeding Related to the Restructuring Act In November 2001, the Company began settlement negotiations with the PRC's utility staff and intervenors in PRC proceedings related to the Restructuring Act in order to resolve a number of matters. Those matters include issues being examined in the Company's merchant plant filing at the PRC, the future framework for restructuring the electric industry in New Mexico under the Restructuring Act, and a future retail electric rate path. The negotiations include the potential implementation and effective date of rates that would replace those approved under the rate freeze stipulation that remains in effect until January 1, 2003. FERC Mandated Regional Transmission Organizations With the passage of the Public Utility Regulatory Policies Act of 1978 and 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. Barriers have been reduced for companies wishing to build, own and operate electric generating facilities. In 1996, the FERC issued Order 888 which required electric utilities controlling transmission facilities to file open access transmission tariffs, which opened the utility transmission systems to wholesale sellers and buyers of electric energy on a non-discriminatory basis. Order 888 also encouraged utilities to investigate the formation of independent system operators ("ISOs") to operate transmission assets and provided guidance for the formation, operation and governance of ISOs. In 1999, the FERC issued Order 2000 on Regional Transmission Organizations ("RTOs"), which established timelines for transmission owning entities to join an RTO and defined the minimum characteristics and functions of an RTO. The Company, along with other regional transmission owners ("TO's"), originally pursued the formation of an RTO through Desert STAR, a non-profit organization. Later because of FERC's acceptance of a for-profit RTO model and because a for-profit RTO was viewed as having the proper motivation to efficiently facilitate competitive markets, the Company and the TO's formed WestConnect RTO, LLC ("WestConnect"), a for-profit transmission company. On October 16, 2001, WestConnect filed its complete RTO package with FERC requesting a Declaratory Order confirming the WestConnect filing satisfies FERC's Order 2000 requirements. There were over 50 intervenors in the WestConnect docket including the New Mexico Attorney General, New Mexico Industrial Energy Consumers and the New Mexico Public Regulation Commission. WestConnect filed a response to the intervenors' concerns on December 17, 2001. 10 Uncertainty exists regarding FERC's evolving RTO policy. WestConnect is participating in various workshops and rulemakings before the FERC and is pursuing avenues to expand its scope so as to enhance its chances for approval as one of the RTOs in the West. FERC Rulemakings Over the past few months, FERC has issued numerous rulemakings. The Company is following the rulemakings and will submit its comments or will comment in conjunction with the Edison Electric Institute ("EEI"). WestConnect is also following, attending workshops and commenting on the rulemakings, which affect the member companies, including the Company. The rulemakings of particular interest to the Company include: o Standardizing Generation Interconnection Agreements and Procedures; o Electricity Market Design and Structure; o Standards of Conduct for Transmission Providers; and o Standards for Business Practices of Interstate Natural Gas Pipelines. PRC Transmission Investigation In July 2001, the AG filed a petition requesting that the PRC initiate an investigation of electric transmission issues including FERC versus PRC jurisdiction and the effect of RTO formation on PRC jurisdiction. The Company suggested workshops to inform the PRC and other interested parties on the issues. The PRC held workshops for three days, and subsequently issued an order requiring that the Company and other transmission-owning entities in the proceeding file comments on jurisdictional issues. PRC Renewable Resources Rulemakings By Notice of Proposed Rulemaking dated February 26, 2002, the PRC proposed the adoption of a new Rule 572 to encourage the development of renewable energy in New Mexico. The Notice provided for the filing of public comments and scheduled a public hearing for April 23, 2002. Among other things, proposed new Rule 572 would establish a renewable portfolio standard of two percent by September 1, 2003, increasing to five percent by September 1, 2005 and ten percent by September 1, 2007. No more than fifty percent of a utility's renewable energy resources portfolio would be allowed to be from any single type of renewable resource for purposes of compliance with the portfolio standard. The Company will submit comments to the PRC. The Company is unable to predict the outcome of this rulemaking proceeding. Gas Rates and Regulation Purchase Gas Adjustment Clause The Company's retail gas rate tariffs contain a PGAC that provides timely recovery for the cost of gas purchased for resale to its sales-service customers. In 2001, the Company presented workshops to the PRC, advocating that the PGAC balancing account be reconciled on a monthly basis, rather than annually. The Company also advocated that it be allowed to earn a return on the balancing account balance. A final order was issued in July 2001 that approves an agreement among the parties regarding the Company's hedging strategy and the implementation of a price management fund program which includes a continuous monthly balancing account adjustment factor including a carrying charge set at the pre-tax cost of capital approved by the PRC in the Company's last gas rate proceeding. This carrying charge has the effect of keeping the Company whole on gas purchase transactions whereby the Company is now compensated for the time value of money. 11 Gas Hedging On November 7, 2000, the PRC issued an order allowing but not requiring the Company to implement a financial hedging strategy. The Company utilized gas options as a hedging tool for the 2001-2002 heating season. Due to the tremendous increase in natural gas prices during the previous heating season, the transaction costs relating to hedging activities increased three-fold. Through a series of workshops and hearings held with the PRC and intervening parties, the Company proposed without opposition, a hedging budget up to $12 million for the 2001-2002 heating season. The Company recovered the actual hedging expenditures as a component of the PGAC during the months of October 2001 through February 2002 in equal allotments of $1.88 million. As winter 2001-2002 gas prices were substantially lower than the previous year, the hedges placed for this winter expired unexercised. Discounted Transportation Fee Recovery The Company made a request to begin the recovery of discounted transportation fee amounts from sales and transportation customers. Discounted transportation fee recovery is a holdover issue from the New Mexico State Supreme Court's ruling leaving open that the amounts passing the PRC's cost benefit test were collectible and only the issue of allocation between customers. The discounts passing the PRC's cost benefit test total $4.3 million. A hearing date of April 17, 2002 has been set. Notice of Inquiry on Pipeline Safety In May 2001, the PRC issued a notice of inquiry into whether the PRC should consider adopting new rules including quality of service standards, to protect the public health and safety, public and private property, and the environment by ensuring the integrity of pipeline systems. The PRC requested information from all pipeline operators with underground or above ground facilities in the state. The Company participated in the comments and hearings in this inquiry. Subsequent PRC action is pending. ENVIRONMENTAL MATTERS The Company, in common with other electric and gas utilities, is subject to stringent laws and regulations for protection of the environment by local, state, Federal and tribal authorities. In addition, PVNGS is subject to the jurisdiction of the NRC, which has authority to issue permits and licenses and to regulate nuclear facilities in order to protect the health and safety of the public from radioactive hazards and to conduct environmental reviews pursuant to the National Environmental Policy Act. 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 acts may have been lawful at the time they occurred. (See "Management's Discussion and Analysis - Critical Accounting Policies - Contingencies - Environmental Issues" for a discussion of applicable accounting policies). 12 The Clean Air Act On July 1, 1999, the EPA published its final regional haze regulations. The purpose of the regional haze regulations is to address regional haze visibility impairment in the 156 Class 1 areas in the nation, which consist of national parks, wilderness areas and other similar areas. The final rule calls for all states to establish goals and emission reduction strategies for improving visibility in all the Class 1 areas. The Company cannot predict at this time what the impact of the implementation of the regional haze rule will be on the Company's coal-fired power plant operations. Potentially, additional SO2 emission reductions could be required in the 2013-2018 timeframe. The nature and cost of compliance with these potential requirements cannot be determined at this time. However, the Company does not anticipate any material adverse impact on the Company's financial condition or results of operations. New Source Review Rules The 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 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 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 the 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 administrations in Washington. The National Energy Policy released May 2001 by the National Energy Policy Development Group, called for a review of the pending NSR enforcement actions and that review continues by the EPA. If the EPA should prevail with its current interpretation of the NSR and NSPS rules, the Company may be required to make significant capital expenditures which could have a material adverse effect on the Company's financial position and results of operations. Threatened Citizen Suit Under the Clean Air Act By letter dated January 9, 2002, counsel for the Grand Canyon Trust and Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a so-called "citizen suit" under the Clean Air Act, alleging that the Company and co-owners of the SJGS violated the Clear Air Act, and the implementing federal 13 and state regulations at SJGS. The notice indicates that penalties and injunctive relief may be sought. Under the Clear Air Act, GCT must wait at least 60 days after affording the Company notice (i.e., until March 9, 2002) before filing a lawsuit. GCT has not yet filed suit. The allegations contained in GCT's notice of intent to sue fall into three categories. First, GCT contends that the plant has violated, and is currently in violation, of the federal New Source Performance Standards ("NSPS") at all four units at SJGS. Second, GCT argues that the plant has violated, and is currently in violation, of the federal PSD rules, as well as the corresponding provisions of the New Mexico Administrative Code, at all four units. Third, GCT alleges that the plant has "regularly violated" the 20% opacity limit contained in SJGS' operating permit and set forth in federal and state regulations at Units 1, 3 and 4. The Company is currently investigating the allegations contained in the notice of intent to sue. Based on its investigation to date, the Company firmly believes that the allegations are without merit. By letter to GCT's counsel dated February 22, 2002, the Company vigorously disputed the allegations. The Company adheres to high environmental standards as evidenced by its International Standards Organization ratings. In that letter, the Company also stated that the GCT has failed to provide sufficient information to permit full examination of the allegations and affirmed its compliance with the laws in question. If a lawsuit is filed by GCT, as threatened, the Company will respond on behalf of the co-owners and vigorously defend in the litigation. However, the Company is unable to predict the ultimate outcome of the matter. Santa Fe Generating Station ("Santa Fe Station") The Company and the NMED conducted investigations of the gasoline and chlorinated solvent groundwater contamination detected beneath the Company's former Santa Fe Station site to determine the source of the contamination pursuant to a 1992 Settlement Agreement ("Settlement Agreement") between the Company and the NMED. No source of groundwater contamination was identified as originating from the site. However, in June 1996, the Company received a letter from the NMED, indicating that the NMED believed the Company is the source of gasoline contamination in a City of Santa Fe municipal supply well and of groundwater underlying the Santa Fe Station site. Further, the NMED letter stated that the Company was required to proceed with interim remediation of the contamination pursuant to the New Mexico Water Quality Control Commission regulations. In October 1996, the Company and the NMED signed an amendment to the Settlement Agreement concerning the groundwater contamination underlying the site. As part of the amendment, the Company agreed to spend approximately $1.2 million for certain costs related to sampling, monitoring and the development and implementation of a remediation plan. The amended Settlement Agreement does not, however, provide the Company with a full and complete release from potential further liability for remediation of the groundwater contamination. After the Company has expended the settlement amount, if the NMED can establish through binding arbitration that the Santa Fe Station is the source of the contamination, the Company could be required to perform further remediation that is determined to be necessary. The Company continues to dispute any contention that the Santa Fe Station is the source of the groundwater contamination and believes that insufficient data exists to identify the sources of groundwater contamination. The Company's aquifer characterization and groundwater quality reports compiled from 1996 through 2000 strongly suggest groundwater contamination has been drawn under the site by the pumping of the Santa Fe supply well. 14 The Company and the NMED, with the cooperation of the City of Santa Fe, jointly selected a 3 to 4 year remediation plan proposed by a remediation contractor. The City of Santa Fe, the Company and the NMED entered into a memorandum of understanding concerning the selected remediation plan and the operation of the municipal well adjacent to the Santa Fe Station site in connection with carrying out the plan. On October 5, 1998, a new system began operation to treat groundwater produced by the Santa Fe well to drinking water standards for municipal distribution and bioremediation of groundwater contamination beneath the Santa Fe Station site. Since the reactivation of the Santa Fe well, the groundwater treatment and bioremediation systems have resulted in a marked reduction in contaminant concentrations at the wellhead. However, contaminant concentrations at the property boundary remain high. On October 5, 2001, the bioremediation injection system was shut down so that testing could be conducted to determine the reduction of the contaminant concentrations that has been achieved. Person Station The Company, in compliance with a Corrective Action Directive issued by the NMED, determined that groundwater contamination exists in the deep and shallow groundwater at the Company's Person Station site. The Company is required to delineate the extent of the contamination and remediate the contaminants in the groundwater at the Person Station site. The extent of shallow and deep groundwater contamination was assessed and the results were reported to the NMED. The Company has received the renewal of the RCRA post-closure care permit for the facility. Remedial actions for the shallow and deep groundwater were incorporated into the new permit. The Company has installed and is operating a pump and treat system for the shallow groundwater. The renewed RCRA post-closure care permit allows remediation of the deep groundwater contamination through natural attenuation. The Company's current estimate to decommission its retired fossil-fueled plants (discussed below) includes approximately $4.2 million in additional expenses to complete the groundwater remediation program at Person Station. As part of the financial assurance requirement of the Person Station Hazardous Waste Permit, the Company established a trust fund. In November 2001, the NMED approved the Company's permit modification request to terminate the trust fund. This approval allowed the Company to use an alternative method rather than the trust fund to satisfy the financial assurance requirements for post-closure care. This change was possible due to an improvement in the Company's financial condition. The remediation program continues on schedule. Fossil-Fueled Plant Decommissioning Costs The Company's six owned or partially owned, in-service and retired, fossil-fueled generating stations are expected to incur dismantling and reclamation costs as they are decommissioned. The Company's share of decommissioning costs for all of its fossil-fueled generating stations is projected to be approximately $148.2 million stated in 2001 dollars, including approximately $24.0 million (of which $18.1 million has already been expended) for Person, Prager and Santa Fe Stations which have been retired. The Company is currently recovering estimated decommissioning costs for its in-service fossil-fueled generating facilities through rates charged to its retail customers. COMPETITION Under current law, the Company is not in any direct retail competition with any other regulated electric and gas utility, except for sales of natural gas. Nevertheless, the Company is subject to varying degrees of competition in certain territories adjacent to or within areas it serves that are also currently served by other utilities in its region as well as by rural electric cooperatives and municipal utilities. 15 As a result of the Restructuring Act, as amended, the Company may face competition from companies with greater financial and other resources when customer choice is implemented in 2007. There can be no assurance that the Company will not face competition in the future that would adversely affect its results. EMPLOYEES As of December 31, 2001, the Company had 2,675 full-time employees. The following table sets forth the number of employees by business segment as of December 31, 2001: Number --------- Corporate (1)........................................ 411 Electric Services.................................... 746 Gas Services......................................... 932 Generation and Trading Operations.................... 569 Unregulated Operations............................... 17 --------- Total............................................. 2,675 ========= (1) These employees reside at the Holding Company at December 31, 2001. The number of employees of PNM Resources, Inc. and its subsidiaries who are represented by unions or other collective bargaining groups include (i) Electric Services, 213; (ii) Gas Services, 87; and (iii) Generation and Trading Operations, 339. ITEM 2. PROPERTIES ELECTRIC The Company's ownership and capacity in electric generating stations in commercial service as of December 31, 2001, were as follows: Total Net Generation Capacity Type Name Location (MW) - -------------- ----------------- --------------------------- ------------- Coal........ SJGS (a) Waterflow, New Mexico 765 Coal........ Four Corners (b) Fruitland, New Mexico 192 Gas/Oil..... Reeves Albuquerque, New Mexico 154 Gas/Oil..... Las Vegas Las Vegas, New Mexico 20 Nuclear..... PVNGS (c) Wintersburg, Arizona 390 * ------- 1,521 PPA** 132 ------- 1,653 ======= * For load and resource purposes, the Company has notified the PRC that it recognizes the maximum dependable capacity rating for PVNGS to be 381 MW. ** The Company has a long term PPA for the rights to all output of a gas fired generating plant with maximum dependable capacity of 132 MW. 16 (a) SJGS Units 1, 2 and 3 are 50% owned by the Company; SJGS Unit 4 is 38.5% owned by the Company. (b) Four Corners Units 4 and 5 are 13% owned by the Company. (c) The Company is entitled to 10.2% of the power and energy generated by PVNGS. The Company has a 10.2% ownership interest in Unit 3 and has leasehold interests in approximately 7.9% of Units 1 and 2 and an ownership interest in approximately 2.3% of Units 1 and 2. The Company's owned interests in PVNGS are mortgaged to secure its remaining first mortgage bonds. Fossil-Fueled Plants SJGS is located in northwestern New Mexico, and consists of four units operated by the Company. Units 1, 2, 3 and 4 at SJGS have net rated capacities of 327 MW, 316 MW, 497 MW and 507 MW, respectively. SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson. Unit 3 is owned 50% by the Company, 41.8% by SCPPA and 8.2% by Tri-State. Unit 4 is owned 38.457% by the Company, 28.8% by M-S-R, 10.04% by Anaheim, 8.475% by Farmington, 7.2% by Los Alamos and 7.028% by UAMPS. The Company also owns 192 MW of net rated capacity derived from its 13% interest in Units 4 and 5 of Four Corners located in northwestern New Mexico on land leased from the Navajo Nation and adjacent to available coal deposits. Units 4 and 5 at Four Corners are jointly owned with SCE, APS, Salt River Project, Tucson and El Paso and are operated by APS. Four Corners and a portion of the facilities adjacent to SJGS are located on land held under easements from the United States and also under leases from the Navajo Nation. The enforcement of these leases could require Congressional consent. The Company does not deem the risk with respect to the enforcement of these easements and leases to be material. However, the Company is dependent in some measure upon the willingness and ability of the Navajo Nation to protect these properties. The Company owns 154 MW of generation capacity at Reeves Station in COA and 20 MW of generation capacity at Las Vegas Station in Las Vegas, New Mexico. In addition, the Company has 132 MW of generation capacity in COA under a PPA. These stations and PPA are used primarily for peaking, transmission support and during times of excess capacity, augmentation of the Company's power trading activities. Nuclear Plant The Company's Interest in PVNGS The Company is participating in the three 1,270 MW units of PVNGS, also known as the Arizona Nuclear Power Project, with APS (the operating agent), Salt River Project, El Paso, SCE, SCPPA and the Department of Water and Power of the City of Los Angeles. The Company has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. 17 Nuclear Safety Performance Rating on PVNGS In 2000, the NRC began using a new, objective oversight process that is more focused on safety. The new process includes objective performance thresholds based on insights from safety studies and 30 years of plant operating experience in the United States. It is more timely, moving from the 18 to 24 month time lag of the previous oversight process for assessing plant performance to a quarterly review. The NRC also hopes the process will be more accessible to, and readily understood by, the public. PVNGS has all 38 indicators green (the best possible of the four indicator levels). Steam Generator Tubes APS, as the operating agent of PVNGS, has encountered tube cracking in the steam generators and has taken, and will continue to take, remedial actions that it believes have slowed the rate of tube degradation. The projected service life of steam generators is reassessed periodically and these analyses indicate that it will be economically desirable to replace the Unit 2 steam generators in 2003. In 1997, the PVNGS participants, including the Company, entered into a contract for the fabrication of two replacement steam generators for delivery in 2002. The cost of the new steam generators was updated in late 1999. The Company's share of the fabrication and installation costs will be approximately $23 million. In December 1999, the PVNGS participants unanimously approved installation of the new steam generators in Unit 2. APS, the Company and the other PVNGS participants are currently considering issues related to the potential replacement of the steam generators in Units 1 and 3. Although a final determination of whether Units 1 and 3 will require steam generator replacements to operate over their current full licensed lives has not yet been made, the Company and the other participants have approved an expenditure of $25.6 million (of which the Company's share is $2.6 million) in 2002 and 2003 to procure long lead-time materials for fabrication of a spare set of steam generators for either Unit 1 or 3. This action will provide the PVNGS participants an option to replace the steam generators at either Unit 1 or 3 as early as fall 2005 should they ultimately choose to do so. If the participants decide to proceed with steam generator replacement at both Units 1 and 3, the Company has estimated that its portion of the fabrication and installation costs and associated power uprate modifications would be approximately $47 million over the next five years. Sale and Leaseback Transactions of PVNGS Units 1 and 2 In 1985 and 1986, the Company entered into a total of eleven sale and lease back transactions with an owner trust under which it sold and leased back its entire 10.2% interest in PVNGS Units 1 and 2, together with portions of the Company's undivided interest in certain PVNGS common facilities. The leases under each of the sale and leaseback transactions have initial lease terms expiring January 15, 2015 (with respect to the Unit 1 leases) or January 15, 2016 (with respect to the Unit 2 leases). Each of the leases allows the Company to extend the term of the lease as well as containing a repurchase option. The lease expense for the Company's PVNGS leases is approximately $66.3 million per year. Throughout the terms of the leases, the Company continues to have full and exclusive authority and responsibility to exercise and perform all of the rights and duties of a participant in PVNGS under the Arizona Nuclear Power Project Participation Agreement and retains the exclusive right to sell and dispose of its 10.2% share of the power and energy generated by PVNGS Units 1 and 2. The Company also retains responsibility for payment of its share of all taxes, insurance premiums, operating and maintenance costs, costs related to capital improvements and decommissioning and all other similar costs and expenses associated with the leased facilities. In 1992, the Company purchased 18 approximately 22% of the beneficial interests in the PVNGS Units 1 and 2 leases through the purchase of an ownership interest in the trust which held the leases. The related ownership interests were subsequently reacquired by the Company when the Company's trust ownership was collapsed and the Company assumed direct ownership. In connection with the $30 million retail rate reduction stipulated with the NMPUC in 1994, the Company wrote down the purchased beneficial interests in PVNGS Units 1 and 2 leases to $46.7 million. Each lease describes certain events, "Events of Loss" or "Deemed Loss Events", the occurrence of which 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 provided in the lease and (ii) assume debt obligations relating to the PVNGS lease. The "Events of Loss" generally relate to casualties, accidents and other events at PVNGS, which would severely, adversely affect the ability of the operating agent, APS, to operate, and the ability of the Company to earn a return on its interests in, PVNGS. The "Deemed Loss Events" consist mostly of legal and regulatory changes (such as changes in law making the sale and leaseback transactions illegal, or changes in law making the lessors liable for nuclear decommissioning obligations). The Company believes the probability of such "Events of Loss" or "Deemed Loss Events" occurring is remote for the following reasons: (i) to a large extent, prevention of "Events of Loss" and some "Deemed Loss Events" is within the control of the PVNGS participants, including the Company, and the PVNGS operating agent, through the general PVNGS operational and safety oversight process and (ii) with respect to other "Deemed Loss Events", which would involve a significant change in current law and policy, the Company is unaware of any pending proposals or proposals being considered for introduction in Congress, except as described below under "PVNGS Liability and Insurance Matters", or in any state legislative or regulatory body that, if adopted, would cause any such events. 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 investments in qualified and non-qualified trusts. The results of the 1998 triannual decommissioning cost study indicated that the Company's share of the PVNGS decommissioning costs excluding spent fuel disposal will be approximately $181 million (in 1998 dollars). The Company funded an additional $6.1 million, $3.9 million and $3.1 million in 2001, 2000 and 1999, respectively, into the qualified and non-qualified trust funds. The estimated market value of the trusts at the end of 2001 was approximately $57 million. The NRC amended its rules on financial assurance requirements for the decommissioning of nuclear power plants. The amended rules became effective on November 23, 1998. The NRC has indicated that the amendments respond to the potential rate deregulation in the power generating industry and NRC concerns regarding whether decommissioning funding assurance requirements will need to be modified. The amended rules provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers amounts equal to estimated total decommissioning costs through cost of service rates or through a "non-bypassable charge". Other mechanisms are prescribed, such as prepayment, surety methods, insurance and other guarantees, if the requirements for exclusive reliance on the external sinking fund mechanism are not met. The Company currently relies on the external sinking fund mechanism to 19 meet the NRC financial assurance requirements for its interests in PVNGS Units 1, 2 and 3. The costs of PVNGS Units 1 and 2 are currently included in PRC jurisdictional rates, but the costs of PVNGS Unit 3 are excluded from PRC jurisdictional rates. The Company has filed a report with the NRC through APS, the operating agent of PVNGS, in March 2001, concerning decommissioning funding assurance, and will continue to use the external sinking fund method as the sole financial assurance method for Unit 3 (see Item 7. "Management's Discussion And Analysis Of Financial Condition And Results Of Operations - The Restructuring Act and the Formation of a Holding Company - NRC Prefunding"). 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 domestic power reactors. The NRC, pursuant to the Waste Act, requires operators of nuclear power reactors to enter into spent fuel disposal contracts with the DOE. Under the Waste Act, the DOE was to develop facilities necessary for the storage and disposal of spent nuclear fuel and to have the first facility in operation by 1998. That facility was to be a permanent repository. The DOE has announced that such a repository cannot be completed before 2010. In July 1996, the United States Court of Appeals for the District of Columbia Circuit (D. C. Circuit) ruled that the DOE has an obligation to start disposing of spent nuclear fuel no later than January 31, 1998. By way of letter dated December 17, 1996, the DOE informed the Company and other contract holders that the DOE anticipates that it would be unable to begin acceptance of nuclear spent fuel for disposal in a repository or interim storage facility by January 31, 1998. In November 1997, the D. C. Circuit issued a Writ of Mandamus precluding the DOE from excusing its own delay on the grounds that the DOE has not yet prepared a permanent repository or interim storage facility. On May 5, 1998, the D. C. Circuit issued a ruling refusing to order the DOE to begin moving spent nuclear fuel. (See Note 11 of Notes to the Consolidated Financial Statements in Item 8 for a discussion of interim spent fuel storage costs). On February 15, 2002, the President of the United States approved a recommendation of the Secretary of Energy that the Yucca Mountain site in Southern Nevada be developed for the storage of nuclear spent fuel. The State of Nevada has opposed this site selection and the Company anticipates that there will be a protracted process to address the Yucca Mountain issues. The Company cannot predict the ultimate outcome of this process. APS has storage 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 approximately 2002. Construction of a new facility for on-site dry storage of spent fuel is underway. Once this facility is completed and approvals are granted, APS believes that spent fuel storage or disposal methods will be available for use by PVNGS to allow its continued operation beyond 2002. A new low-level waste facility was built in 1995 on site, which could store an amount of waste equivalent to ten years of normal operation at PVNGS. Although some low-level waste has been stored on site, APS is currently shipping low-level waste to off-site facilities. APS currently believes that interim low-level waste storage methods are or will be available for use by PVNGS to allow its continued operation and to safely store low-level waste until a permanent disposal facility is available. 20 The Company believes that scientific and financial aspects of the issues of spent fuel and low-level waste storage and disposal can be resolved satisfactorily. However, the Company also acknowledges that their ultimate resolution in a timely fashion will require political resolve and action on national and regional scales which the Company is unable to predict at this time. 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 program 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 million, with an annual payment limitation of $3 million per incident. The insureds under this liability insurance include the PVNGS participants and "any other person or organization with respect to his legal responsibility for damage caused by the nuclear energy hazard". If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue raising measures on the nuclear industry to pay claims. Aspects of the Federal law referred to above (the "Price-Anderson Act"), which provides for payment of public liability claims in case of a catastrophic accident involving a nuclear power plant, is up for renewal in August 2002. While existing nuclear power plants would continue to be covered in any event, the renewal would extend coverage to future nuclear power plants and could contain amendments that would affect existing plants. A renewal bill was passed by the House with unanimous consent on November 27, 2001. The House proposed a change in the annual retrospective premium limit from $10 million to $15 million per reactor per incident. Additionally, the House proposed to amend the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident, taking into account effects of inflation. On March 7, 2002 the Senate approved a Price-Anderson Act amendment as a part of the overall energy bill. The Senate version is substantially the same as the Price-Anderson Act in its current form. In the event the energy bill does not pass, it is possible that the Price Anderson amendment will be passed as a stand-alone bill. In a report issued in 1998, the NRC had made a number of recommendations regarding the Price-Anderson Act, including a recommendation that Congress investigate whether the $200 million now available from the private insurance market for liability claims per reactor can be increased to keep pace with inflation. The Company cannot predict whether or not Congress will renew the Price-Anderson Act or act on the NRC's recommendations. However, if adopted, certain changes in the law could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by the lessors. Such an occurrence could require the Company to, among other things, (i) pay the lessor and the equity investor, in return for the investor's interest in PVNGS, cash in the amount as provided in the lease and (ii) assume debt obligations relating to the PVNGS lease (see "Sale and Leaseback Transactions of PVNGS Units 1 and 2" above). 21 The PVNGS participants maintain "all-risk" (including nuclear hazards) insurance for nuclear property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion as of January 1, 2002, a substantial portion of which must be applied to stabilization and decontamination. The Company has also secured insurance against portions of the increased cost of generation or purchased power and business interruption resulting from certain accidental outages of any of the three units if the outages exceed 12 weeks. The insurance coverage discussed in this section is subject to certain policy conditions and exclusions. The Company is a member of an industry mutual insurer. This mutual insurer provides both the "all-risk" and increased cost of generation insurance to the Company. In the event of adverse losses experienced by this insurer, the Company is subject to an assessment. The Company's maximum share of any assessment is approximately $4.8 million per year. Other Electric Properties As of December 31, 2000, the Company owned, jointly owned or leased 2,890 circuit miles of electric transmission lines, 4,488 miles of distribution overhead lines, 3,741 cable miles of underground distribution lines (excluding street lighting) and 222 substations. The Company and Tri-State entered into an asset sale agreement dated September 9, 1999, pursuant to which Tri-State agreed to sell the Company certain assets acquired by Tri-State's merger with Plains Electric Generation and Transmission Cooperative, Inc., consisting primarily of transmission assets, a fifty percent interest in an inactive power plant located near COA, and an office building in Albuquerque. The purchase price was $13.2 million, subject to adjustment at the time of closing with the transaction to close in two phases. The asset sale agreement contains standard covenants and conditions for this type of agreement. On July 1, 2000, the first phase was completed, and the Company acquired the 50 percent ownership in the inactive power plant and the office building. On February 28, 2001, the second phase relating to the transmission assets was completed and the Company acquired ownership of the transmission assets. NATURAL GAS The natural gas properties as of December 31, 2001, consisted primarily of natural gas storage, transmission and distribution systems. Provisions for storage made by the Company include ownership and operation of an underground storage facility located near Albuquerque, New Mexico. The transmission systems consisted of approximately 1,465 miles of pipe with appurtenant compression facilities. The distribution systems consisted of approximately 11,121 miles of pipe. OTHER INFORMATION The electric and gas transmission and distribution lines are generally located within easements and rights-of-way on public, private and Indian lands. The Company leases interests in PVNGS Units 1 and 2 and related property, EIP and associated equipment, data processing, communication, office and other equipment, office space, utility poles (joint use), vehicles and real estate. The Company also owns and leases service and office facilities in Albuquerque and in other areas throughout its service territory. 22 ITEM 3. LEGAL PROCEEDINGS PVNGS Water Supply Litigation The Company understands that a summons served on APS in 1986 required all water claimants in the Lower Gila River Watershed of Arizona to assert any claims to water on or before January 20, 1987, in an action pending in the Maricopa County Superior Court. PVNGS is located within the geographic area subject to the summons and the rights of the PVNGS participants, including the Company, to the use of groundwater and effluent at PVNGS are potentially at issue in this action. APS, as the PVNGS project manager, filed claims that dispute the court's jurisdiction over the PVNGS participants' groundwater rights and their contractual rights to effluent relating to PVNGS and, alternatively, seek confirmation of those 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 in September 2000 affirming the lower court's criteria for resolving 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. San Juan River Adjudication In 1975, the State of New Mexico filed an action entitled State of New Mexico v. United States, et al., in the District Court of San Juan County, New Mexico, to adjudicate all water rights in the "San Juan River Stream System". The Company was made a defendant in the litigation in 1976. The action is expected to adjudicate water rights used at Four Corners and at SJGS. (See Item 1. "Business - Generation and Trading Operations - Fuel and Water Supply - Water Supply".) The Company cannot at this time anticipate the effect, if any, of any water rights adjudication on the present arrangements for water at SJGS and Four Corners. It is the Company's understanding that final resolution of the case cannot be expected for several years. The Company is unable to predict the ultimate outcome. Republic Savings Bank Litigation In 1992, Meadows and its subsidiary RHC filed suit against the Federal government in the United States Court of Claims, alleging breach of contract arising from the seizure of RSB, a wholly-owned subsidiary of RHC. RSB was seized and liquidated after the Financial Institutions Reform, Recovery and Enforcement Act prohibited certain accounting practices authorized by contracts with the Federal government. The Federal government filed a counterclaim alleging breach by RHC of its obligation to maintain RSB's net worth and moved to dismiss Meadows' claims for lack of standing. RSB filed a motion for partial summary judgment on the issue of liability based on the United States Supreme Court's decision in United States v. Winstar Corporation, decided in 1996. The Federal government filed a cross motion for summary judgment and opposed RSB's motion. Decision on those motions is still pending. The parties completed fact based discovery in 1999. Discovery of expert 23 witnesses has not been completed. No trial date has been established. RSB amended its summary judgment motion in December 1999, to seek summary judgment on the issue of damages. The Federal government opposes RSB's amended motion. Oral argument on this motion was conducted in September 2000. The judge requested additional briefing, which has been submitted. Decision on this motion is still pending. It is premature to estimate the amount of recovery, if any, by Meadows and RHC. Purported Navajo Environmental Regulation Four Corners is located on the Navajo Reservation and is held under easement granted by the Federal government as well as leases from the Navajo Nation. APS is the operating agent and the Company owns a 13% ownership interest in Units 4 and 5 of Four Corners. In July 1995 the Navajo Nation enacted the Navajo Nation Air Pollution Prevention and Control Act, the Navajo Nation Safe Drinking Water Act and the Navajo Nation Pesticide Act (collectively, the "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 Four Corners and as operating agent and joint owner of SJGS, and owners of other facilities located on other reservations located in New Mexico, 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 the 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 the EPA. On October 30, 2001, the DC Circuit issued its opinion granting the Company's appeal concerning the federal operating permits. The Court remanded the proceeding to the EPA for a new rulemaking on the EPA's authority to issue federal operating permits in areas in which status as Indian Country may be in dispute. The United States did not file a petition for rehearing in the appeal. The Company will continue to monitor developments in connection with the remand of this appeal and cannot predict the outcome of this matter. Royalty Claims Natural Gas Royalties Qui Tam Litigation On June 28, 1999, a complaint was served on the Company alleging violations of the False Claims Act by the Company and its subsidiaries, Gathering Company and Processing Company (collectively called the "Company," for purposes of this discussion), by purportedly failing to properly measure natural 24 gas from Federal and tribal properties in New Mexico, and consequently, underpaid royalties owed to the Federal government. A private relator is pursuing the lawsuit. The complaint was served after the United States Department of Justice declined to intervene to pursue the lawsuit. The complaint seeks actual damages, treble damages, costs and attorneys fees, among other relief. This case was consolidated with approximately 70 others, asserting similar claims against other defendants in other jurisdictions, and transferred to Federal District Court for the District of Wyoming by the Federal Multi-District Litigation panel (MDL Panel), recaptioned as In re: Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293. The Company joined 250 other defendants in a motion to dismiss the complaint for failure to plead properly in November 1999. On May 18, 2001, the Wyoming court denied defendants' motion 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 A class action lawsuit against several hundred defendants, including the Company, formerly captioned as Quinque Operating Co. et al. v. Gas Pipelines, et al., C.A. No. 99-CV-30, now captioned as Will price et al., v. Gas Pipelines et al., 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. On January 23, 2002, the plaintiffs filed a Notice of Dismissal with the Kansas court dismissing all claims against the Company without prejudice. KAFB CONTRACT In 1999, the Company was informed that the DOE had entered into an agency agreement with WAPA on behalf of KAFB, one of the Company's largest retail electric customers, by which WAPA would competitively procure power for KAFB. The proposed wholesale power procurement was to begin at the expiration of KAFB's power service contract with the Company in December 1999. On May 4, 1999, the Company received a request for network transmission service from WAPA pursuant to Section 211 of the Federal Power Act to facilitate the delivery of wholesale power to KAFB over the Company's transmission system. The Company denied WAPA's request, by letter dated June 30, 1999, citing the fact that KAFB is and will continue to be a retail customer until the date that KAFB can elect customer choice service under the provisions of the Restructuring Act of 1999. The Company also cited several provisions of Federal law that prohibit the provision of such service to WAPA. On October 1, 1999, WAPA filed a petition requesting the FERC, on an expedited basis, to order the Company to provide network transmission service to WAPA on behalf of DOE and several other entities located on KAFB under the Company's Open Access Transmission Tariff. The petition claimed KAFB is a wholesale customer of the Company, not a retail customer. By order entered on April 13, 2001 the FERC denied the WAPA transmission application. The FERC order determined, among other things, that WAPA had failed to demonstrate that its sales to DOE are sales for resale and also that WAPA failed to qualify for certain claimed exemptions under the Federal Power Act that would have entitled it to provide expanded service to DOE. WAPA requested rehearing of FERC's April 13, 2001 order. 25 In a proposed order issued on June 13, 2001, FERC granted WAPA's request for rehearing. FERC determined that WAPA qualified for an exemption to the prohibition against an order requiring service to retail customers and that FERC therefore could require the Company to provide the requested service. FERC directed the Company and WAPA to engage in negotiations concerning rates, terms and conditions of service, including compensation. On January 18, 2002, the parties submitted a settlement agreement resolving most of the issues relating to the rates, terms and conditions of service. The partial settlement reserved one issue for FERC decision or further proceedings. The reserved issue relates to whether WAPA is entitled to a credit against payments for transmission service for certain facilities located near KAFB. The 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 settlement agreement filed at FERC on January 18, 2002 reserves the Company's rights to seek rehearing and judicial review of any final order and to present other legal claims. On February 14, 2002, the FERC administrative judge who supervised the negotiations leading to the partial settlement recommended that FERC approve the settlement. 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 and KAFB continues to purchase retail service pending resolution of all relevant issues. The PRC case has been held in abeyance, pending the outcome of the FERC proceeding. AVISTAR SEVERANCE When the Company sold its water utility assets to the City of Santa Fe ("City") in 1995, the parties also entered into a Maintenance and Operations Agreement ("Agreement"), agreeing that the City would offer employment to the water utility employees when the Agreement expired. The Agreement was assigned to Avistar, Inc., and it expired in July 2001. The City assumed all maintenance and operations, and offered employment to the employees. Because the employees would continue performing the same jobs at the same location(s), the Company had previously excluded the non-union employees from eligibility for severance benefits under the Company's non-union severance plans. Similarly, the IBEW Local 611 had been on notice that the Company had negotiated for the continued employment of the IBEW-represented employees, making them ineligible for severance benefits under Article 24 of the Collective Bargaining Agreement ("CBA") between the Company and the IBEW. In July 2001, the Agreement ended, and most of the water operations employees accepted employment with the City. However, on March 27, 2001, the IBEW began an internal grievance claiming that about twenty-eight represented employees now employed by the City are nonetheless eligible for severance benefits under Article 24 of the CBA. The Company has denied their eligibility. Local 611 has demanded arbitration of the dispute under the CBA. The Company is unaware of an arbitration date being scheduled. Local 611 seeks to ensure that all laid-off employees receive severance benefits as provided for in Article 24. 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. 26 WESTERN RESOURCES On November 9, 2000, the Company and Western Resources announced that both companies' Boards of Directors approved an agreement under which the Company would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing. In July, 2001, the KCC issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger. Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001 in New York state court seeking declarations that the transaction could not be accomplished as designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. On November 19, 2001, Western Resources filed a complaint against the Company in New York state court alleging breach of contract and breach of implied covenant of good faith and fair dealing. Western Resources alleged that the Company brought about the KCC orders, failed to assist in efforts to reverse the KCC orders, refused to renegotiate within the terms of the agreement, interfered with Western Resources's efforts to satisfy the terms of the agreement, and effected an unauthorized de facto termination of the agreement by filing its complaint. Western Resources alleges damages in excess of $650 million. The Company believes that the complaint filed by Western Resources is without merit and intends to vigorously defend itself against the complaint. The Company also intends to vigorously pursue its own complaint. On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. 27 On February 5, 2002, the District Court for Shawnee County, Kansas, dismissed without prejudice Western Resources' appeal of the KCC's split-off orders. The Court ruled that, by filing a new financial plan in compliance with the orders, Western Resources accepted certain portions of the orders thereby creating a situation where further administrative action became necessary. As a result, the Court concluded that the matter was not ripe for judicial review and remanded the case to the KCC. On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate order. The Company is unable to predict the ultimate outcome of its litigation with Western Resources. REEVES STATION ENVIRONMENTAL MATTERS On August 15, 2001, the COA Air Quality Division of the Environmental Health Department issued a Notice of Violation to the Company, alleging that in the period of March 10, 1998 through June 30, 2001, the Company had exceeded the pound-per-hour NOx limitations in the operating permit for the Reeves 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 COA to attempt to achieve a resolution of the matter. The parties have entered into a settlement agreement that resolves the matter without the admission of liability by the Company. The Company's consolidated financial statements for the year ended December 3, 2001 reflect this settlement agreement. 28 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. SUPPLEMENTAL ITEM. EXECUTIVE OFFICERS OF PNM RESOURCES Executive officers, their ages, offices held with PNM Resources as follows on December 31, 2001:
Name Age Office Initial Effective Date ---- --- ------ ---------------------- J. E. Sterba............ 46 Chairman, President and Chief Executive Officer December 31, 2001 R.J. Flynn.............. 59 Executive Vice President, Electric and Gas Services December 31, 2001 W.J. Real............... 53 Executive Vice President, Power Production and Marketing December 31, 2001 B. L. Barsky............ 57 Senior Vice President, Communications Investor Services and Community Relations December 31, 2001 M. D. Christensen*...... 53 Senior Vice President, Enterprise Solutions December 31, 2001 A. A. Cobb.............. 54 Senior Vice President, Peoples Services and Development December 31, 2001 M. H. Maerki............ 61 Senior Vice President and Chief Financial Officer and President and Chief Executive Officer, Avistar, Inc. December 31, 2001 P. T. Ortiz............. 51 Senior Vice President, General Counsel and Secretary December 31, 2001 E. Padilla, Jr.......... 48 Senior Vice President, Bulk Power Marketing and Development December 31, 2001 R. B. Ridgeway.......... 43 Senior Vice President, Energy Services December 31, 2001 J. R. Loyack............ 38 Vice President, Corporate Controller and Chief Accounting Officer December 31, 2001
(See Public Service Company of New Mexico on pages 30-31 for prior year positions held). - --------------------- All officers are elected annually by the Board of Directors of the Company. * As of February 4, 2002, M.D. Christensen stepped down as Senior Vice President of Enterprise Solutions as a result of the dissolution of Enterprise Solutions. 29 EXECUTIVE OFFICERS OF PUBLIC SERVICE COMPANY OF NEW MEXICO Executive officers, their ages, offices held with Public Service Company of New Mexico in the past five years and initial effective dates thereof, except as otherwise noted:
Name Age Office Initial Effective Date ---- --- ------ ---------------------- J. E. Sterba........... 46 Chairman, President and Chief Executive October 1, 2000 Officer President and Chief Executive Officer June 6, 2000 President March 1, 2000 Executive Vice President, USEC, Inc. December 31, 1998 Executive Vice President and Chief Operating Officer (of the Company) March 11, 1997 Senior Vice President, Bulk Power Services (of the Company) December 6, 1994 R. J. Flynn............ 59 Executive Vice President, Electric and Gas Services January 18, 1999 Senior Vice President, Electric Services December 1, 1994 W. J. Real............. 53 Executive Vice President, Power Production and Marketing January 18, 1999 Senior Vice President, Gas Services December 6, 1994 B. L. Barsky........... 57 Senior Vice President, Communications Investor Services and Community Relations July 3, 2001 Senior Vice President, Corporate Strategy and Investor Relations February 19, 2000 Senior Vice President, Planning and Investor Services August 10, 1999 Senior Vice President and Corporate Secretary January 18, 1999 Vice President, Strategy, Analysis and Investor Relations December 10, 1996 M. D. Christensen*..... 53 Senior Vice President, Enterprise Solutions March 7, 2000 Senior Vice President, Shared Services October 1, 1999 Senior Vice President, New Mexico Retail Services November 3, 1997 Senior Vice President, Customer Service and Public Affairs January 9, 1996
30
Name Age Office Initial Effective Date ---- --- ------ ---------------------- A. A. Cobb............. 54 Senior Vice President, Peoples Services and Development September 11, 2001 Global Human Resources Officer, Clientlogic November 22, 1999 Executive Vice President, Human Resources, Aames Financial February 2, 1999 Senior Vice President, Human Resources, Aames Financial November 1, 1996 M. H. Maerki........... 61 Senior Vice President and Chief Financial Officer, and President and Chief Executive Officer, Avistar, Inc. September 14, 2001 Senior Vice President and Chief Financial Officer December 7, 1993 P. T. Ortiz............ 51 Senior Vice President, General Counsel and Secretary August 10, 1999 Senior Vice President and General Counsel January 18, 1999 Senior Vice President, Regulatory Policy, General Counsel and Secretary December 7, 1993 E. Padilla, Jr......... 48 Senior Vice President, Bulk Power Marketing and Development February 8, 2000 Vice President, Bulk Power Marketing and Development December 14, 1996 R. B. Ridgeway......... 43 Senior Vice President, Energy Services September 14, 2001 Senior Vice President and President and Chief Operating Officer, Avistar August 11, 1999 Senior Vice President, Energy Services December 14, 1996 Vice President, Corporate Planning August 10, 1996 J. R. Loyack........... 38 Vice President, Corporate Controller and Chief Accounting Officer July 19, 1999 Director, Financial Reporting, Union Pacific Corporation October 1, 1998 Senior Manager, Business Analysis, Union Pacific Corporation January 1, 1996
- --------------------- All officers are elected annually by the Board of Directors of PNM. * As of February 4, 2002, M.D. Christensen stepped down as Senior Vice President of Enterprise Solutions as a result of the dissolution of Enterprise Solutions. 31 PART II ITEM 5. MARKET FOR THE COMPANY'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's common stock is traded on the New York Stock Exchange. Ranges of sales prices of the Company's and its predecessor's common stock, reported as composite transactions (Symbol: PNM), and dividends declared on the common stock for 2001 and 2000, by quarters, are as follows: Range of Quarter Ended Sales Prices --------------- -------------------------- Dividends High Low Per Share -------------------------- ------------ 2001 December 31 ................ 28 17/25 24 7/20 $0.20 September 30 ............... 33 11/20 24 18/25 0.20 June 30 .................... 37 4/5 28 7/10 0.20 March 31 ................... 29 7/20 22 7/8 0.20 ----- Fiscal Year .............. 37 4/5 22 7/8 $0.80 ===== 2000 December 31 ................ 28 5/16 203/4 $0.20 September 30 ............... 26 11/25 15 3/8 0.20 June 30 .................... 18 15 5/16 0.20 March 31 ................... 16 11/16 14 5/8 0.20 ----- Fiscal Year .............. 28 5/16 14 5/8 $0.80 ===== On December 31, 2001, the Company's Board of Directors ("Board") declared a quarterly cash dividend of 20 cents per share of common stock payable February 15, 2002, to shareholders of record as of February 4, 2002. On January 31, 2002, there were 15,389 holders of record of the Company's common stock. See Management's Discussion and Analysis of Results of Operations and Financial Condition - "Liquidity and Capital Resources - Dividends," for a discussion on the payment of future dividends. 32 Cumulative Preferred Stock While isolated sales of PNM's cumulative preferred stock have occurred in the past, PNM is not aware of any active trading market for its cumulative preferred stock. Quarterly cash dividends were paid on PNM's cumulative preferred stock at the stated rates during 2001 and 2000. ITEM 6. SELECTED FINANCIAL DATA The selected financial data should be read in conjunction with the consolidated financial statements, the notes to consolidated financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations.
2001 2000 1999 1998 1997 ------------- ------------- ------------- ------------ ------------- (In thousands except per share amounts and ratios) Total Operating Revenues............................. $2,352,098 $1,611,274 $1,157,543 $1,092,445 $1,020,521 Earnings from Continuing Operations.................. $ 150,433 $ 100,946 $ 79,614 $ 95,119 $ 86,497 Net Earnings......................................... $ 150,433 $ 100,946 $ 83,155 $ 82,682 $ 80,995 Earnings per Common Share: Continuing Operations.............................. $ 3.83 $ 2.54 $ 1.93 $ 2.27 $ 2.05 Basic.............................................. $ 3.83 $ 2.54 $ 2.01 $ 1.97 $ 1.92 Diluted............................................ $ 3.77 $ 2.53 $ 2.01 $ 1.95 $ 1.91 Cash Flow Data: Net cash flows provided from operating activities.. $ 324,995 $ 240,947 $ 213,045 $ 210,988 $ 213,122 Net cash flows used in investing activities........ $ (407,014) $ (158,932) $ (55,886) $ (340,992) $ (182,067) Net cash flows generated (used) by financing activities......................... $ 385 $ (94,723) $ (98,040) $ 173,089 $ (33,112) Total Assets......................................... $2,934,638 $2,894,233 $2,723,268 $2,668,603 $2,407,410 Long-Term Debt, including current maturities......... $ 953,884 $ 953,823 $ 988,489 $1,008,614 $ 714,345 Common Stock Data: Market price per common share at year end.......... $ 27.950 $ 26.813 $ 16.250 $ 20.438 $ 23.688 Book value per common share at year end............ $ 25.87 $ 23.64 $ 21.79 $ 20.63 $ 19.26 Average number of common shares outstanding........ 39,118 39,487 41,038 41,774 41,774 Cash dividend declared per common share............ $ 0.80 $ 0.80 $ 1.00 $ 0.60 $ 0.68 Return on Average Common Equity.................... 14.8% 11.1% 9.5% 9.9% 10.2% Capitalization: Common stock equity................................ 50.8% 48.6% 46.7% 45.4% 52.6% Preferred stock without mandatory redemption Requirements..................................... 0.6 0.7 0.7 0.7 0.8 Long-term debt, less current maturities............ 48.6 50.7 52.6 53.9 46.6 ------------- -------------- ------------- ------------- ------------- 100.00% 100.00% 100.00% 100.00% 100.00% ============= ============== ============= ============= =============
(See Comparative Operating Statistics which appear immediately following the Consolidated Financial Statements for additional information regarding operations.) Due to the discontinuance of the natural gas trading operations of its Energy Services Business Unit in 1998 certain prior year amounts have been reclassified as discontinued operations. 33 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Management's Discussion and Analysis of Financial Condition and Results of Operations for PNM Resources, Inc. (the "Company") and Public Service Company of New Mexico ("PNM") is presented on a combined basis. The Company as an unconsolidated holding company ("Holding Company") had no material operations for the year ended December 31, 2001. Except for its consolidated investment in PNM, the Holding Company's only assets were cash of $11 million, short-term investments of $10 million and long-term investments of $106 million at December 31, 2001. In addition, the Holding Company had no liabilities at December 31, 2001. Accordingly, the reader of this Management's Discussion and Analysis of Financial Condition and Results of Operations should assume that the information presented applies to consolidated results of operations and financial position of both the Company and PNM, except where the context or references clearly indicate otherwise. Discussions regarding specific contractual obligations generally reference the company that is legally obligated. In the case of contractual obligations of PNM, these obligations are consolidated with the Company under Generally Accepted Accounting Principles. Broader operational discussion references the Company. The following is management's assessment of the Company's financial condition and the significant factors affecting the results of operations. This discussion should be read in conjunction with the Company's consolidated financial statements. Trends and contingencies of a material nature are discussed to the extent known and considered relevant. OVERVIEW The Company is an investor-owned holding company of energy and energy related companies. Its principal subsidiary, PNM, is an integrated public utility primarily engaged in the generation, transmission, distribution and sale and trading of electricity; transmission, distribution and sale of natural gas within the State of New Mexico and the sale and trading of electricity in the Western United States. The Company's principal business segments are Utility Operations, which include Electric Services ("Electric") and Gas Services ("Gas"), and Generation and Trading Operations ("Generation and Trading"). Electric consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment for accounting purposes due to its immateriality, and for purposes of this discussion, it is combined with the distribution business line. The Company's wholly-owned subsidiary, Avistar, Inc. ("Avistar"), provides unregulated energy services. Upon the completion on December 31, 2001, of a one-for-one share exchange between PNM and the Company, the Company became the parent company of PNM. Prior to the share exchange, the Company had existed as a subsidiary of PNM. The new holding company began trading on the New York Stock Exchange under the same PNM symbol beginning on December 31, 2001. COMPETITIVE STRATEGY The Company is positioned as a "merchant utility," primarily operating as a regulated energy service provider also engaged in the sale and trading of electricity in the competitive energy market place. As a utility, the Company has an obligation to serve its customers under the jurisdiction of the New Mexico Public Regulation Commission ("PRC"). As a merchant, the Company markets 34 excess production from the utility, as well as, unregulated generation and its purchases for resale into a competitive market place. The merchant operations utilize an asset-backed trading strategy, whereby the Company's aggregate net open position for the sale of electricity is covered by the Company's excess generation capabilities. The benefits of the merchant operations are shared with retail customers based on a negotiated settlement in proportion to capacity owned, expended effort, and risk assumed. Non-regulated assets may be part of the utility company or owned by an affiliate of the utility company, which could be a subsidiary of the holding company. Currently, all non-regulated assets, except Avistar, are part of the utility. Both retail customers and shareholders benefit from this combination. The Electric and Gas Services strategy is directed at supplying reasonably priced and reliable energy to retail customers through customer driven operational excellence, quality processes, and improved overall organizational performance. The Generation and Trading strategy calls for increased asset-backed trading and generation capacity supported by long-term contracts, as well as improved risk management strategies. The Company's plans to increase generation calls for approximately 50% of its wholesale activity to be committed through long-term contracts, including its sales to jurisdictional customers. Such growth will be dependent on market developments, and upon the Company's ability to generate funds for the Company's expansion. (Intentionally left blank) 35 RESULTS OF OPERATIONS Year Ended December 31, 2001 Compared to Year Ended December 31, 2000 Consolidated The Company's net earnings available to common shareholders for the year ended December 31, 2001 were $149.8 million, a 49.3% increase over net earnings of $100.4 million in 2000. This increase reflects strong market pricing in the Western United States in the first half of 2001 and continuing growth in utility operations. Earnings in both 2001 and 2000 were affected by certain special gains and non-recurring charges. These special items are detailed in the individual business segment discussions below. The following table enumerates these special gains and non-recurring charges and shows their effect on diluted earnings per share, in thousands, except per share amounts.
2001 2000 ------------------------ ------------------------- EPS EPS Earnings (Diluted) Earnings (Diluted) ------------ ----------- ------------ ------------ (Income)/Expense Net Earnings Available for Common Shareholders.................................. $149,847 $3.77 $100,360 $2.53 ------------ ----------- ------------ ------------ Adjustment for Special Gains and Charges (net of income tax effects): Contribution to PNM Foundation................. 3,021 0.08 - - Nonrecoverable coal mine decommissioning costs................... 7,840 0.20 - - Write-off of Avistar investments............... 7,907 0.20 - - Settlement of lawsuit.......................... - - (8,306) (0.21) Resolution of two gas rate cases............... - - (2,808) (0.07) Impairment of certain tax related regulatory assets................ - - 6,552 0.16 Costs for the acquisition of long-term wholesale customer........................... - - 2,740 0.07 Western Resources acquisition costs............ 10,859 0.27 4,047 0.10 ------------ ----------- ------------ ------------ Total........................................ 29,627 0.75 2,225 0.05 ------------ ----------- ------------ ------------ Net Earnings Available For Common Shareholders Excluding Special Gains and Charges................................... $179,474 $4.52 $102,585 $2.58 ============ =========== ============ ============
To adjust reported net earnings and diluted earnings per share to exclude the special gains and non-recurring charges, special gains, net of income tax expense, are subtracted from reported net earnings under Generally Accepted Accounting Principles ("GAAP") and non-recurring charges, net of income tax benefit, are added back to reported net earnings under GAAP. 36 The following discussion is based on the financial information presented in the Consolidated Financial Statements - Segment Information note. The tables below set forth the operating results for each business segment. Year Ended December 31, 2001
Utility ---------------------------------- Generation Electric Gas and Trading --------------- --------------- ---------------- Operating revenues: External customers....................... $ 559,226 $385,418 $1,405,916 Intersegment revenues.................... 707 - 341,608 --------------- --------------- ---------------- Total revenues........................... 559,933 385,418 1,747,524 --------------- --------------- ---------------- Cost of energy sold........................ 5,102 251,296 1,280,168 Intersegment purchases..................... 341,608 - 707 --------------- --------------- ---------------- Total cost of energy..................... 346,710 251,296 1,280,875 --------------- --------------- ---------------- Gross margin............................... 213,223 134,122 466,649 --------------- --------------- ---------------- Administrative and other costs............. 41,275 45,973 27,969 Energy production costs.................... 924 1,946 149,585 Depreciation and amortization.............. 32,666 21,465 42,766 Transmission and distribution costs........ 37,376 31,072 553 Taxes other than income taxes.............. 12,247 6,812 8,777 Income taxes............................... 27,264 5,957 82,629 --------------- --------------- ---------------- Total non-fuel operating expenses........ 151,752 113,225 312,279 --------------- --------------- ---------------- Operating income........................... $ 61,471 $20,897 $ 154,370 --------------- --------------- ----------------
Year Ended December 31, 2000
Utility ---------------------------------- Generation Electric Gas and Trading --------------- --------------- ---------------- Operating revenues: External customers....................... $538,758 $319,924 $750,434 Intersegment revenues.................... 707 - 324,744 --------------- --------------- ---------------- Total revenues........................... 539,465 319,924 1,075,178 --------------- --------------- ---------------- Cost of energy sold........................ 5,048 195,334 749,499 Intersegment purchases..................... 324,744 - 707 --------------- --------------- ---------------- Total cost of energy..................... 329,792 195,334 750,206 --------------- --------------- ---------------- Gross margin............................... 209,673 124,590 324,972 --------------- --------------- ---------------- Administrative and other costs............. 38,975 37,963 27,355 Energy production costs.................... 1,208 1,485 137,202 Depreciation and amortization.............. 31,480 19,994 41,558 Transmission and distribution costs........ 33,092 27,206 30 Taxes other than income taxes.............. 13,819 8,295 11,219 Income taxes............................... 30,516 7,605 26,083 --------------- --------------- ---------------- Total non-fuel operating expenses........ 149,090 102,548 243,447 --------------- --------------- ---------------- Operating income........................... $60,583 $22,042 $81,525 --------------- --------------- ----------------
37 Year Ended December 31, 1999
Utility ---------------------------------- Generation Electric Gas and Trading --------------- --------------- ---------------- Operating revenues: External customers....................... $540,868 $236,711 $371,109 Intersegment revenues.................... 707 - 318,872 --------------- --------------- ---------------- Total revenues........................... 541,575 236,711 689,981 --------------- --------------- ---------------- Cost of energy sold........................ 4,493 112,925 414,534 Intersegment purchases..................... 318,872 - 707 --------------- --------------- ---------------- Total cost of energy..................... 323,365 112,925 415,241 --------------- --------------- ---------------- Gross margin............................... 218,210 123,786 274,740 --------------- --------------- ---------------- Administrative and other costs............. 52,586 49,716 26,791 Energy production costs.................... 2,632 1,504 132,787 Depreciation and amortization.............. 30,183 19,210 41,183 Transmission and distribution costs........ 31,013 28,227 23 Taxes other than income taxes.............. 19,014 6,915 9,006 Income taxes............................... 24,451 2,112 6,951 --------------- --------------- ---------------- Total non-fuel operating expenses........ 159,879 107,684 216,741 --------------- --------------- ---------------- Operating income........................... $58,331 $16,102 $57,999 --------------- --------------- ----------------
Utility Operations Electric - Operating revenues increased $20.5 million or 3.8% for the period to $559.9 million. Retail electricity delivery grew 2.3% to 7.3 million MWh in 2001 compared to 7.1 million MWh delivered in the prior year period, resulting in increased revenues of $8.9 million year-over-year. This volume increase was the result of load growth from economic expansion in New Mexico. In addition, revenues from third party use of the Company's transmission system increased $9.6 million as a result of additional contracts, while revenues also benefited from a $1.1 million increase in revenue from property leasing. The following table shows electric revenues by customer class and average customers: Electric Revenues (Thousands of dollars) 2001 2000 ------------ ------------ Residential.................... $187,600 $186,133 Commercial..................... 242,372 238,243 Industrial..................... 82,752 79,671 Other.......................... 47,209 35,418 ------------ ------------ $559,933 $539,465 ============ ============ Average Customers.............. 378,000 369,000 ============ ============ 38 The following table shows electric sales by customer class: Electric Sales (Megawatt hours) 2001 2000 ---------- ---------- Residential..................... 2,198 2,172 Commercial...................... 3,213 3,134 Industrial...................... 1,603 1,544 Other........................... 241 239 ---------- ---------- 7,255 7,089 ========== ========== The gross margin, or operating revenues minus cost of energy sold, increased $3.6 million, which reflects the increased energy sales, transmission revenue and property leasing revenue, partially offset by higher cost for the electricity sold to retail customers. Electric exclusively purchases power from Generation and Trading at Company developed prices which are not based on market rates. These intercompany revenues and expenses are eliminated in the consolidated results. Administrative and general costs increased $2.3 million or 5.9% for the period. This increase is primarily due to increased pension and post-retirement benefits expense resulting primarily from a reduction in expected investment returns on plan assets. Consulting expenses focused on cost control and process improvement initiatives also contributed to the increase. These increases were partially offset by lower bad debt and collection expense. By December 2000, the Company had resolved most of the problems associated with the implementation of its new billing system. As a result bad debt expense was significantly lower in 2001. Transmission and distribution costs increased $4.3 million or 12.9% primarily due to a non-recurring increase in maintenance to improve reliability for the transmission and distribution systems. Taxes other than income decreased $1.6 million or 11.4% reflecting favorable audit outcomes by certain tax authorities and tax planning strategies. Gas - Operating revenues increased $65.5 million or 20.5% for the period to $385.4 million. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, increased gas revenues driven by increased gas costs do not impact the Company's gross margin or earnings. The revenue increase was driven primarily by a 17.6% increase in average gas prices in the first half of 2001, resulting from increased market demand. In addition, a 3.1% volume increase and a gas rate increase, which became effective October 30, 2000 contributed to the increase. The gas rate increase added $7.8 million of revenue. Transportation volume increased 14.7% or $6.1 million. This growth was primarily attributed to gas transportation customers whose increased demand was driven by the strong power market in the Western United States during the first half of 2001. This increase is not expected to recur in 2002. Approximately $28.1 million of gas revenue in 2001 was attributable to the Company's Generation and Trading Operations and is eliminated in the consolidated results. 39 The following table shows gas revenues by customer and average customers: Gas Revenues (Thousands of dollars) 2001 2000 ----------- ------------ Residential......................... $232,321 $191,231 Commercial.......................... 68,895 52,964 Industrial.......................... 27,519 24,206 Transportation*..................... 20,188 14,163 Other............................... 36,495 37,360 ----------- ------------ $385,418 $319,924 =========== ============ Average customers................... 443,000 435,000 =========== ============ The following table shows gas throughput by customer class: Gas Throughput (Thousands of decatherms) 2001 2000 ---------- ---------- Residential.......................... 27,848 28,810 Commercial........................... 10,421 9,859 Industrial........................... 3,920 5,038 Transportation*...................... 51,395 44,871 Other................................ 4,355 6,426 ---------- ---------- 97,939 95,004 ========== ========== *Customer-owned gas. The gross margin, or operating revenues minus cost of energy sold, increased $9.5 million or 7.7%. This increase is due to the rate increase and higher transportation volumes, which will likely not recur in 2002, as discussed above. Administrative and general costs increased $8.0 million or 21.1%. This increase is due to increased pension and post-retirement benefits expense resulting primarily from a reduction in expected investment returns on plan assets, consulting expenses in connection with cost control and process improvement initiatives, partially offset by decreased bad debt and collection costs. Depreciation and amortization increased $1.5 million or 7.4% for the period due to a higher depreciable plant base. Transmission and distribution costs increased $3.9 million or 14.2% primarily due to a non-recurring increase in maintenance to improve reliability for the transmission and distribution systems, as the Company continues to focus on improving reliability and effectiveness of its retail distribution system. 40 Taxes other than income decreased $1.5 million or 17.9% due to favorable audit outcomes by certain tax authorities and tax planning strategies. Generation and Trading Operations A spike in regional wholesale electric prices occurred in the first half of 2001 and the second half of 2000. This spike was caused by the power supply/demand imbalance in the Western United States, limited power generation capacity and increased natural gas prices. The Company does not believe that the high wholesale prices seen in 2001 and 2000 will recur in 2002. At the end of the second quarter of 2001, the market experienced falling price levels. This trend continued in the last half of 2001. As a result, market liquidity - the opportunity to buy and resell power profitably in the marketplace - also declined reflecting the bankruptcy of a major market trader and limited price volatility. The Company believes that current weak market pricing is not sustainable and that prices will adjust to more normal historical levels in the second half of 2002. Operating revenues grew $672.3 million or 62.5% for the period to $1.7 billion. This increase in wholesale electricity sales primarily reflects the strong regional wholesale electric prices in the first half of 2001. The Company delivered wholesale (bulk) power of 12.6 million MWh of electricity this period, compared to 12.4 million MWh in the prior period. Wholesale revenues from third-party customers increased from $750.4 million to $1.4 billion, an 87.3% increase. The following table shows revenues by customer class: Generation and Trading Revenues By Market (Thousands of dollars) 2001 2000 ----------------- ------------------ Intersegment sales................. $ 341,608 $ 324,744 Firm-requirements wholesale........ 24,754 15,540 Other wholesale sales*............. 1,381,162 734,894 ----------------- ------------------ $ 1,747,524 $ 1,075,178 ================= ================== The following table shows sales by customer class: Generation and Trading Sales By Market (Megawatt hours) 2001 2000 -------------- --------------- Intersegment sales.................. 7,255,297 7,088,943 Firm-requirements wholesale......... 616,703 330,003 Other wholesale sales............... 11,960,397 12,022,125 -------------- --------------- 19,832,397 19,441,071 ============== =============== *Includes mark-to-market gains/(losses). 41 The gross margin, or operating revenues minus cost of energy sold, increased $141.7 million or 43.6%. The Company's margins benefit significantly from rising gas prices as most of the Company's generation portfolio is fueled by stable priced fuel sources, such as coal and uranium. As the increase in gas prices puts upward pressure on electricity prices, the profitability of the Company's stable low-cost generation increases significantly. Margins also benefited from the Company's power trading activities. The Company buys and then resells electricity in the market generating incremental margin by taking advantage of price changes in the electricity sales market. In addition, the Company also tailors electric deliveries for its wholesale customers creating incremental margin opportunities. Generally, as market prices decline, trading volumes rise supporting margin levels in lower price electric markets. These higher margins were partially offset by a year-over-year increase in unrealized mark-to-market losses of $21.0 million which the Company recognized relating to its power trading contracts. Administrative and general costs increased $0.6 million or 2.2% for the period. This increase is primarily due to increased pension and post-retirement benefits expense, higher power marketing expenses of $1.0 million mainly for additional incentive bonuses and certain consulting fees, and other expenses related to business development and process improvement. This increase was partially offset by lower year-over-year Generation and Trading business development costs due to significant costs related to the acquisition of a long-term wholesale customer. Energy production costs increased $12.4 million or 9.0% for the year. The increase is primarily due to higher maintenance costs in 2001 resulting from scheduled and unscheduled outages at Palo Verde Nuclear Generating Station ("PVNGS"), San Juan Generating Station ("SJGS") and Reeves Generating Station ("Reeves"), additional incentive bonuses at SJGS, and increased generation at Reeves, one of the Company's gas generation facilities, which has a higher cost of production than the Company's coal and nuclear facilities. This increase was partially offset by lower maintenance costs at Four Corners Power Plant ("Four Corners") as a result of decreased outage time. A significant unscheduled outage occurred in the fall of 2001 at SJGS. The Company took advantage of the outage to accelerate its outage scheduled for the spring of 2002. As a result, maintenance costs and the related lost market potential of the accelerated outage will be avoided in the spring of 2002. Depreciation and amortization increased $1.2 million or 2.9% for the period due to a higher depreciable plant base. Taxes other than income decreased $2.4 million or 21.8% as a result of favorable audit outcomes by certain tax authorities and tax planning strategies. Unregulated Businesses In July 2001, the Board of Directors of Avistar decided to wind down all unregulated operations except for Avistar's Reliadigm business unit, which provides maintenance solutions and technologies to the electric power industry. Avistar had previously divested itself of its Energy Partners business unit and liquidated Axon Field Services and Pathways Integration. This divestiture was largely in response to market disruptions caused by the California energy crisis. In addition, the transfer of operation of the Sangre de Cristo Water Company to the City of Santa Fe was completed in the third quarter. All remaining non-Reliadigm investments were written-off with the exception of Avistar's investment in Nth Power, an energy related venture capital fund. These write-downs reflect the significant decline in the technology market and bankruptcy of these investees. The Company recorded non-operating charges of $13.1 million to reflect these activities and the impairment of its Avistar investments. 42 Due to the cessation of much of Avistar's historic operations, business activity declined significantly. Revenues decreased 30.8% for the period to $1.5 million. Operating losses for Avistar decreased from $4.6 million in the prior year period to $4.2 million in the current year period primarily due to decreased costs as a result of the shutdown of certain operations. In January 2002, Avistar was dividended to PNM Resources by PNM. Corporate Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, decreased $1.4 million for the period to $32.1 million. This decrease was due to lower bonus expense in 2001 and reorganizational costs incurred in 2000 that did not occur in 2001 due to the delay in separating Utility Operations from Generation and Trading Operations. These cost improvements were partially offset by higher legal costs associated with routine business operations and increased pension and post-retirement benefit expense. Other Non-Operating Costs Other income and deductions, net of taxes, decreased $41.3 million for the period to a loss of $7.4 million. On a pre-tax basis in 2000, the Company recognized gains of $13.8 million related to the settlement of a lawsuit, $4.5 million for the reversal of certain reserves associated with the resolution of two gas rate cases and $2.4 million related to the Company's hedge of certain non-qualified retirement plan trust assets. In the current year, the Company recorded pre-tax charges of $13.1 million to write-off certain permanently impaired Avistar investments and $13.0 million of non-recoverable coal mine decommissioning costs previously established as a regulatory asset. The Company will continue to evaluate the recoverability of regulatory assets as the rate making process occurs and will identify its stranded costs, if any, when it files its new transition plan that is due by January 1, 2005. The current year results also include the following pre-tax items: a donation of $5.0 million to the PNM Foundation; unrecoverable costs of $2.3 million related to an abandoned transmission line expansion project; a year-over-year decrease in investment income of $5.6 million on the PVNGS decommissioning trust assets; and increased costs of $5.5 million related to the Company's terminated acquisition of Western Resources' electric utility operations, partially offset by $3.4 million of equity income from a passive investment. Total costs for the year ended December 31, 2001 related to the Company's terminated acquisition of Western Resources were $18.0 million pre-tax. The Company has expensed all costs related to the terminated transaction to date. The Company's consolidated income tax expense was $81.1 million in the twelve months ended December 31, 2001, an increase of $6.7 million for the year. The impact of higher earnings was partially mitigated by the reversal of $6.6 million of valuation allowances taken against certain income tax related regulatory assets in 2000 that the Company determined would continue to be recoverable in rates largely due to the delay in the implementation of deregulation. The Company's effective income tax rates for the years ended 2001 and 2000 were 35.02% and 42.41%, respectively. Excluding the impact of the valuation reserve changes, the Company's effective income tax rates for the years ended 2001 and 2000 were 37.85% and 38.67%, respectively. The decrease in the effective rate was primarily due to the favorable tax treatment received on the 2001 equity earnings discussed above. 43 Year Ended December 31, 2000 Compared to Year Ended December 31, 1999 Consolidated The Company's net earnings available to common shareholders for the year ended December 31, 2000 were $100.4 million, a 22% increase over net earnings of $82.6 million in 1999. This increase reflects strong market pricing in the Western United States in the second half of 2000 and continuing growth in utility operations. Earnings in both 2000 and 1999 were affected by certain special gains and charges. These special items are detailed in the individual business segment discussions below. The following table enumerates these special gains and charges and shows their effect on diluted earnings per share, in thousands, except per share amounts.
2000 1999 ------------------------- -------------------------- EPS EPS Earnings (Diluted) Earnings (Diluted) ------------ ------------ ------------- ------------ (Income)/Expense Net Earnings Available for Common Shareholders................................... $100,360 $2.53 $82,569 $2.01 ------------ ------------ ------------ ------------ Adjustment for Special Gains and Charges (net of income tax effects): Settlement of lawsuit........................... (8,306) (0.21) - - Resolution of two gas rate cases................ (2,808) (0.07) - - Impairment of certain tax related regulatory assets............................. 6,552 0.16 - - Costs for the acquisition of long-term wholesale customer............................ 2,740 0.07 - - Western Resources acquisition costs............. 4,047 0.10 - - Equity income from a passive investment......... - - (4,180) (0.10) Mine closure activities......................... - - (1,227) (0.03) Bad debt costs associated with system implementation problems....................... - - 4,890 0.12 Cumulative effect of an accounting change....... - - (3,541) (0.09) ------------ ------------ ------------ ------------ Total.......................................... 2,225 0.05 (4,058) (0.10) ------------ ------------ ------------ ------------ Net Earnings Available For Common Shareholders Excluding Special Gains and Charges.................................... $102,585 $2.58 $78,511 $1.91 ============ ============ ============ ============
To adjust reported net earnings and diluted earnings per share to exclude the special gains and non-recurring charges, special gains, net of income tax expense, are subtracted from reported net earnings under GAAP and non-recurring charges, net of income tax benefit, are added back to reported net earnings under GAAP. 44 Utility Operations Electric - Operating revenues declined $2.1 million or 0.4% for the year to $539.5 million due to the implementation in late July 1999 of the rate order lowering rates by $22.2 million year-over-year. This was mostly offset by increased retail electricity delivery of 7.1 million MWh compared to 6.8 million MWh delivered in the prior year period, a 4.2% improvement which increased revenues $21.8 million year-over-year. This increased volume was the result of warm temperatures and load growth. The following table shows electric revenues by customer class: Electric Revenues (Thousands of dollars) 2000 1999 ------------ ------------ Residential..................... $186,133 $184,088 Commercial...................... 238,243 238,830 Industrial...................... 79,671 85,828 Other........................... 35,418 32,829 ------------ ------------ $539,465 $541,575 ============ ============ Average Customers............... 369,000 361,000 ============ ============ The following table shows electric sales by customer class: Electric Sales (Megawatt hours) 2000 1999 ---------- ---------- Residential...................... 2,172 2,028 Commercial....................... 3,134 2,982 Industrial....................... 1,544 1,559 Other............................ 239 235 ---------- ---------- 7,089 6,804 ========== ========== The gross margin, or operating revenues minus cost of energy sold, decreased $8.5 million. This decline reflects the rate reduction discussed above. Electric exclusively purchases power from Generation and Trading at Company developed prices which are not based on market rates. Administrative and general costs decreased $13.6 million or 25.9% for the year. This decrease is due to non-recurring Year 2000 ("Y2K") compliance costs and non-recurring costs related to the Company's implementation of its new customer billing system in 1999. In addition, in 1999, as a result of significant increases in delinquent accounts due to system implementation problems, the Company incurred additional bad debt costs of $5.5 million above its normal experience rate. Bad debt expense in 2000 was $4.9 million, a 29.9% decline for the year. 45 Energy production costs decreased $1.4 million or 54.1% for the year primarily due to non-recurring Y2K compliance costs in 2000. Depreciation and amortization increased $1.3 million or 4.3% for the year. The increase is due to the impact of amortizing the costs of the new customer billing system, which has a five-year amortization life, and depreciating the expansion of the electric distribution system. Transmission and distribution costs increased $2.1 million or 6.7% for the year primarily due to increased scheduled maintenance of transmission lines and the addition of station related equipment for reliability purposes. This increase in scheduled maintenance continued in 2001. Taxes other than income decreased $5.2 million or 27.3% due to a change in the recognition of electric franchise fees collected from customers and payable to municipalities, partially offset by the impact of the implementation of the new customer billing system on the collection of certain taxes and an increase in expected tax liabilities. Franchise fees were a part of the Company's rate structure in 1999. In 2000, they were unbundled from the rate structure. As a result, the Company now passes through directly to customers the franchise fees charged by municipalities and does not incur expense or generate revenues as a result of collecting the fees. Gas - Operating revenues increased $83.2 million or 35.2% for the year to $319.9 million. The Company purchases natural gas in the open market and resells it at cost to its distribution customers. As a result, increased gas revenues driven by increased gas costs do not impact the Company's gross margin or earnings. The increase was driven by a 31.3% increase in gas prices in the later months of 2000 as a result of increased market demand, a 3.0% volume increase. The following table shows gas revenues by customer class: Gas Revenues (Thousands of dollars) 2000 1999 ------------ ------------- Residential......................... $191,231 $152,266 Commercial.......................... 52,964 37,337 Industrial.......................... 24,206 8,550 Transportation*..................... 14,163 12,390 Other............................... 37,360 26,168 ------------ ------------- $319,924 $236,711 ============ ============= Average customers................... 435,000 426,000 ============ ============= 46 The following table shows gas throughput by customer class: Gas Throughput (Thousands of decatherms) 2000 1999 ---------- ---------- Residential........................... 28,810 32,121 Commercial............................ 9,859 11,106 Industrial............................ 5,038 2,338 Transportation*....................... 44,871 40,161 Other................................. 6,426 6,538 ---------- ---------- 95,004 92,264 ========== ========== *Customer-owned gas. The gross margin, or operating revenues minus cost of energy sold, increased $0.8 million or 0.7%. This increase is due to higher retail customer distribution volumes on which the Company earns cost of service revenues. Administrative and general costs decreased $11.8 million or 23.6%. This decrease is mainly due to non-recurring Y2K compliance costs, customer billing system costs and lower associated bad debt costs. The Electric and Gas Services share the same billing system, and Gas Services experienced the same delinquency problems discussed above in the "Electric" results of operations. As a result, in 1999, the Company incurred additional bad debt costs of $2.1 million above its normal experience rate. However, bad debt expense did not significantly decline in 2000 as the Company increased its bad debt costs by approximately $2 million in anticipation of a higher than normal delinquency rate driven by the significantly higher natural gas prices experienced in November and December 2000. This trend is similar to historic collection trends associated with past gas price spikes. Depreciation and amortization increased $0.8 million or 4.1% for the year. The increase is due to the impact of amortizing the costs of a new customer billing system and depreciating the expansion of the gas transmission system. Transmission and distribution costs decreased $1.0 million or 3.6% primarily due to non-recurring Y2K compliance costs. Taxes other than income increased $1.4 million or 20.0% primarily due to higher tax liabilities and the impact of the implementation of the new customer billing system on the collection of certain taxes. Generation and Trading Operations Operating revenues grew $385.2 million or 55.8% for the year to $1.08 billion. This increase in wholesale electricity sales reflects strong regional wholesale electric prices caused by a warm summer, limited power generation capacity, increasing natural gas prices and the power supply imbalance in the Western United States. These factors contributed to unusually high wholesale 47 prices which the Company does not believe to be sustainable in the long-term, although these factors continued to affect markets in the first half of 2001. The Company delivered wholesale (bulk) power of 12.4 million MWh this period compared to 11.2 million MWh delivered last year, an increase of 10.6%. The MWh increase is attributable to increased trading activity during the year. Wholesale revenues from third-party customers increased from $371.1 million to $750.4 million, a 102.2% increase. The increase was largely price driven. The following table shows revenues by customer class: Generation and Trading Operations Revenues By Market (Thousands of dollars) 2000 1999 ---------------- --------------- Intersegment sales...................... $ 324,744 $ 318,872 Firm-requirements wholesale............. 15,540 7,046 Other wholesale sales*.................. 734,894 364,063 ---------------- --------------- $ 1,075,178 $ 689,981 ================ =============== The following table shows sales by customer class: Generation and Trading Operations Sales By Market (Megawatt hours) 2000 1999 -------------- --------------- Intersegment sales...................... 7,088,943 6,803,583 Firm-requirements wholesale............. 330,003 179,249 Other wholesale sales................... 12,022,125 10,992,372 -------------- --------------- 19,441,071 17,975,204 ============== =============== *Includes mark-to-market gains/(losses). The gross margin, or operating revenues minus cost of energy sold, increased $50.2 million or 18.3%. Higher margins were partially offset by $8.5 million of losses associated with the Company's assessment of risk in the wholesale market and unrealized mark-to-market losses of $4.8 million which the Company recognized relating to its power trading contracts. These items were recorded as revenue adjustments. Administrative and general costs increased $3.6 million or 2.1% for the year. This increase is due to a one-time charge of $4.5 million in connection with the acquisition of a new, long-term wholesale customer and an increase in bad debt costs, partially offset by non-recurring Y2K compliance costs and lower legal costs related to a lawsuit settlement involving the Company's decommissioning trust which was settled in August 2000. The settlement was recorded as other income. Energy production costs increased $4.4 million or 3.3% for the year. These costs are generation related. The increase is due to higher maintenance costs resulting from scheduled outages at San Juan Unit 3 and Four Corners Unit 4, which were partially offset by lower PVNGS employee costs as a result of additional employee incentive and retiree healthcare costs in the prior year that did not recur in 2000 and additional PVNGS billings in 1999 for 1998 expenses as a result of an audit by the station owners. 48 Taxes other than income increased $2.2 million or 24.6% due to higher tax liabilities. Unregulated Businesses Avistar contributed $2.2 million in revenues for the year compared to $8.9 million in the comparable prior year period due to lower business volumes resulting from slow developing markets associated with Avistar's new product offerings. Operating losses for Avistar increased from $4.4 million in the prior year to $6.6 million in the current year. Corporate Corporate administrative and general costs, which represent costs that are driven exclusively by corporate-level activities, increased $8.0 million for the year to $33.5 million. This increase was due to additional administrative and consulting expenses for strategic initiatives, higher legal costs and reorganizational costs incurred in anticipation of separating utility operations under the Restructuring Act. Other Non-Operating Costs Other income and deductions, net of taxes, increased $4.2 million for the year to $34.4 million due to certain special gains. The Company recognized on a pre-tax basis $13.2 million related to the settlement of a lawsuit and $4.6 million before income taxes associated with the resolution of two gas rate cases. The current year also had increased mark-to-market gains on the Company's hedge of its investments for nuclear decommissioning and certain post retirement benefits. These gains were partially offset by $6.7 million of costs related to the Company's terminated Western Resources transaction. In addition, other income and deductions included a valuation loss recognized for Avistar's AMDAX.com investment, and expenses related to the transfer of the operation of the City of Santa Fe's water system to the municipality. In 1999, other income and deductions included gains, on a pre-tax basis, of $4.2 million of equity income from a passive investment and $2.0 million from closing down certain coal mine reclamation activities in an inactive subsidiary. Net interest charges decreased $4.7 million for the period to $65.9 million primarily as a result of the retirement of $31.6 million of senior unsecured notes in June and August 1999 and $32.8 million in January 2000. The Company's consolidated income tax expense, before the cumulative effect of an accounting change, was $74.3 million, an increase of $32.0 million for the year. The Company's 2000 income tax effective rate, before the cumulative effect of the accounting change, was 42.41%. Included in the Company's 2000 income tax expense is the write-off of $6.6 million of income tax-related regulatory assets. Excluding the write-off of income tax-related regulatory assets, the Company's effective tax rate was 38.67%. The Company's 1999 effective tax rate was 34.70%. The increase in the rate was primarily due to the favorable tax treatment received on the 1999 equity earnings in other income and deductions discussed above. 49 FUTURE EXPECTATIONS Because of the wholesale market price decline in the Western United States that began in the second half of 2001, the Company's 2002 earnings are not expected to reach 2001 levels. On January 23, 2002, the Company announced that it expects its 2002 earnings to be at the lower end of the previously identified range of $3.00 to $3.50 per share. Wholesale prices in the West currently remain at lower levels than the Company believes likely to prevail through the remainder of 2002; however, the Company expects this reduced pricing environment to continue through much of the first and second quarters. The Company's view is based on a return to normal weather, a beginning of economic recovery by summer and the reemergence of liquidity in the wholesale market that was impacted by the bankruptcy of a major trader and credit quality reduction of other market traders. Accordingly, the Company believes that the lower end of the range, $3.00 per share in earnings, is achievable for 2002, and the first quarter earnings are likely to be consistent with trends from the first quarter in 2000. However, if wholesale prices in the West do not increase as forecasted by the Company, the Company's earnings are likely to be lower than its identified range of $3.00 to $3.50. The calculation of future expected earnings is subject to numerous variables, including, on and off-peak wholesale demand, retail load needs, natural gas prices, generating resource availability, the current position of the Company's trading portfolio and general economic conditions. As a result of the reduced pricing environment, many generators have announced the cancellation of previously planned projects. The Company expects that forward prices will again move upwards in future periods as result of under building. 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 over the long-term. 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. This discussion of future expectations is forward looking information within the meaning of Section 21E of the Securities Exchange Act of 1934. The achievement of expected results is dependent upon the assumptions described in the preceding discussion, and is qualified in its entirety by the Private Securities Litigation Reform Act of 1995 disclosure - (see "Disclosure Regarding Forward Looking Statements" below) - and the factors described within the disclosure that could cause the Company's actual financial results to differ materially from the expected results enumerated above. CRITICAL ACCOUNTING POLICIES The preparation of financial statements in conformity with GAAP requires the Company to select and apply accounting policies that best provide the framework to report the Company's results of operations and financial position. The selection and application of those policies require management to make difficult subjective or complex judgments concerning reported amounts of revenue and expenses during the reporting period and the reported amounts of assets and liabilities at the date of the financial statements. The judgments and uncertainties inherent in this process affect the application of those policies. As a result, there exists the likelihood that materially different amounts would be reported under different conditions or using different assumptions. Management has identified the following accounting policies that it deems critical to the portrayal of the Company's financial condition and results and that involve significant subjectivity. Management believes that its selection and application of these policies best represent the operating results and financial position of the Company. The following discussion provides information on the processes utilized by management in making judgments and assumptions as they apply to its critical accounting policies. 50 Revenue Recognition The Company recognizes revenues in the period of delivery. The Company's Utility Operations are required to estimate revenues for unbilled services when its billing cycle does not match the calendar-end reporting period. Management's estimates are based on models which utilize actual units delivered and the applicable rate structure. Utility Operation's gas operating revenues exclude adjustments for differences in gas purchase costs that are above or below levels included in base rates but are recoverable under the mechanism established by the PRC. Utility Operations recognize this adjustment when it is permitted to bill under PRC guidelines. Utility Operations, also, periodically hedge natural gas purchases to limit commodity price volatility. Unrealized gains and losses from natural gas-related swaps, futures and forward contracts are deferred and recognized as the natural gas is sold and is recovered through gas rates charged to customers. The Company enters into energy trading contracts to take advantage of market opportunities associated with the purchase and sale of electricity. Unrealized gains and losses resulting from the impact of price movements on Generation and Trading Operations' contracts are recognized as adjustments to Generation and Trading Operations operating revenues. These adjustments are based on market prices that are actively quoted. Financial Instruments Under the derivative accounting rules and the related accounting rules for energy trading activities, the Company accounts for its various financial derivative instruments for the purchase and sale of energy differently based on Management's intent when entering into the contract. Energy trading contracts are recorded at fair market value at each period end. The changes in fair market value are recognized in earnings. Non-trading contracts must be accounted for as derivatives and recorded in the balance sheet as either an asset or liability measured at their fair value. Changes in the derivatives' fair value are recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Should an energy transaction qualify as a hedge, fair market value changes from period to period are recognized on the balance sheet with a corresponding charge to other comprehensive income. Gains or losses are recognized when the hedged transaction occurs. Normal purchases and sales are not marked-to-market but rather recorded in results of operations when the underlying transaction occurs. The market prices used to value the Company's energy trading contracts are based on closing exchange prices and over-the-counter quotations. As of December 31, 2001, the Company does not have any outstanding contracts that were valued using methods other than quoted prices. The Company did not change its methods for valuing its trading contracts in 2001 as compared to 2000. The Company recognized a $25.8 million loss related to its mark-to-market adjustment in 2001. This represents the net change in the Company's mark-to-market 51 adjustment for its trading contracts from December 31, 2000 to December 31, 2001. The following table summarizes the Company's trading portfolio at December 31 (in thousands): 2001 2000 -------------- -------------- Face value of contracts................... $(41,193) $ (6,314) Market value of contracts................. (10,753) (1,672) -------------- -------------- Mark-to-market loss....................... $(30,440) $ (4,642) ============== ============== The trading portfolio positions at December 31, 2001 and 2000 represent net liabilities after netting all open purchase and sale contracts. Because the contractual amounts required to settle the net liability were greater than the current market values of the contracts, the Company recognized mark-to-market losses for the differences in 2001 and 2000. As of December 31, 2001, a decrease in market pricing of the Company's trading contracts by 10% would have resulted in a decrease in net earnings of less than 1%. Conversely, an increase in market pricing of the Company's trading contracts by 10% would have resulted in an increase in net earnings of less than 1%. At December 31, 2001, the market value of the Company's normal sales and purchases of electricity was a $1.7 million liability using the valuation methods described above. If these transactions were classified as trading or did not meet the definition of normal under the accounting rules for derivatives, the Company would have recognized unrealized gains of $18.2 million as an adjustment to Generation and Trading Operations operating revenues based on the change in fair value of these contracts from January 1, 2001 to December 31, 2001. In addition to the fair market valuation described above, the Company provides for losses due to market and credit risk in the electric wholesale marketplace based on its assessment of counterparty default risk. This assessment is based on a methodology that considers the credit ratings of the Company's counterparties, the price volatility in the marketplace, the fair market value of all contracts outstanding and management's evaluation of market trends that are expected to impact market risk. The resulting amount is recorded as an adjustment to revenue. Increases in market prices, increases in an individual counterparty's credit position and general economic conditions which may impact the credit ratings of the Company's counterparties will generally result in an increased market volatility and credit risk and a corresponding reduction to revenues. Regulatory Assets and Liabilities The accounting rules for rate regulated entities require a company to reflect the effects of regulatory decisions in its financial statements. In accordance with these accounting rules, the Company has deferred certain costs that are rate recoverable and recorded certain liabilities for amounts to be returned to retail customers pursuant to the rate actions of the PRC and its predecesor and the Federal Energy Regulatory Commission ("FERC"). Substantially all of the Company's regulatory assets and regulatory liabilities are reflected in rates charged to retail customers or have been addressed in a regulatory proceeding. To the extent that management concludes that the recovery of a regulatory asset is no longer probable due to changes in regulatory treatment, the effects of competition or other factors, the amount would be recorded as a charge to earnings as recovery is no longer probable. The Company currently has fixed electricity rates for jurisdictional service purposes until January 2003. If the present rates were materially reduced, management would need to re-evaluate the recoverability of its regulatory assets. If management were to determine that the new rate structure would not be sufficient to recover these regulatory assets, the Company would be required to record a charge for the portion of the costs that were not recoverable. The Company has discontinued the application of regulatory accounting as of December 31, 1999, for the generation portion of its business effective with the passage in New Mexico of the Electric Utility Industry Restructuring Act of 1999. The Company evaluates these assets under the same impairment rules that it uses to evaluate tangible long-lived assets. In 2001, the Company determined certain costs would not be recovered and recorded a charge of $13.1 million to earnings for these amounts. The Company believes that it will recover costs associated with its remaining stranded assets, including asset closure costs, through a non-bypassable charge as permitted by the Restructuring Act, or in 52 future rate cases prior to implementation of customer choice. If management were to determine that the expected non-bypassable charge or other rate treatment would not be sufficient to recover these costs, the Company would be required to record a charge to earnings for that portion of the costs that were not recoverable. Asset Impairment The Company regularly evaluates the carrying value of its tangible long-lived assets in relation to their future undiscounted cash flows to assess recoverability in accordance with accounting rules. Impairment testing of power generation assets is performed periodically in response to changes in market conditions resulting from industry deregulation and other market trends. Power generation assets used to supply jurisdictional and wholesale markets are evaluated on a group basis using future undiscounted cash flows based on current open market price conditions. The Company also has generation assets that are used for the sole purpose of reliability. These assets are tested as an individual group. Power generation assets held under operating leases are not currently evaluated for impairment as prescribed by current GAAP. The Company's estimate of future undiscounted cash flows is based on its assumptions of future market trends for the price of electricity such as demand, pricing and volatility. Adverse developments in the wholesale electricity market that lead to less favorable assumptions about future market trends could result in an impairment of the Company's power generation assets. Contingent Liabilities There are various claims and lawsuits pending against the Company and certain of its subsidiaries. The Company has recorded a liability where the effect of litigation can be estimated and where an outcome is considered probable. Management's estimates are based on its knowledge of the relevant facts at the time of the issuance of the Company's Consolidated Financial Statements. Subsequent developments could materially alter management's assessment of a matter's probable outcome and the estimate of the Company's liability. Environmental Issues 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 53 site using currently available information, including existing technology, current 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). LIQUIDITY AND CAPITAL RESOURCES At December 31, 2001, the Company had cash and short-term and long-term investments of $176.8 million compared to $107.7 million in 2000. The Company's long-term investments are highly liquid though its intent is to hold them longer than one year. Cash provided from operating activities in the year ended December 31, 2001 was $325.0 million, an increase of $84.0 million from 2000. This increase was primarily the result of increased profitability. Contributing to this increase was the recovery of the cost of purchased gas from utility customers deferred in accordance with PRC regulations. In addition, the Company was not required to 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 was made in January 2002. Partially offsetting these cash inflows was the impact of lower wholesale electric and gas prices at year end 2001, resulting in a decrease in accounts payable; however, these same price decreases led to an offsetting decrease in accounts receivable. This market effect resulted in a net cash outflow of $60.5 million, year-over-year. Cash used for investing activities was $407.0 million in 2001 compared to $158.9 million in 2000. This increase reflects the movement of $150.0 million of cash to investments with longer maturities, ranging from one to three years, and greater yields. In addition, cash used for investing activities includes construction expenditures related to the Company's announced new generating plants of $103.4 million in 2001 compared to $13.0 million for similar expenditures in 2000 and expenditures of $14.0 million in 2001 related to the acquisition of certain transmission assets and other related investing activities compared to $5.8 million for similar expenditures in 2000. The Company continues to make significant investments in its generation portfolio. Cash generated by financing activities was $0.4 million compared to $94.7 million of cash used in 2000. Financing activities in 2001 were primarily short-term borrowings for liquidity reasons, offset by cash payments for dividend requirements. The use of cash in 2000 reflects the repurchase of $34.7 million of senior unsecured notes at a cost of $32.8 million and common stock repurchases of $27.9 million. Pension and Other Postretirement Benefits In 2001, the investment market experienced significant declines due to various reasons. In addition, the future outlook for the investment market is not expected to improve in the short term. As a result, the Company adjusted the expected rate of return on its pension and other postretirement benefit plans assets. For the year ended December 31, 2001, the Company's net periodic benefit 54 cost assumed a 7.75% rate of return as compared to 9.00% in the prior year. The rate adjustment reflects the Company's outlook for asset returns after considering the events of September 11, 2001 and the impact of asset losses recognized in the September 30, 2001 plan valuation. This change resulted in an increase of $4.2 million in the Company's recorded net periodic benefit expense. In addition, increases in the health care cost trend contributed an additional $3.2 million of increased costs. Total net periodic benefit cost for all plans was $11.3 million in 2001 as compared to $4.6 million in 2000. The actual return on the plan's assets for the year ended December 31, 2001 was a loss of $36.2 million. As a result, the Company recorded a tax effected decrease in other comprehensive income of $28.9 million. The actual losses recorded in other comprehensive income will be recognized in the Company's future results of operations to the extent that future calculations of the net periodic benefit expense's assumed rate of return reflects the losses. The accounting rules for pension plans and other postretirement benefits allow investment gains and losses to be recognized in a systematic and rational method. This methodology reduces the periodic impact of market volatility. In January 2002, the Company made an aggregate contribution of $23.5 million to fund the pension and other postretirement benefit plans. The effect of this contribution will be to reduce the impact that the actual investment losses will have on the Company's future net periodic benefit cost. In addition, the Company believes that its expected rate of return in 2002 will be at historical levels. Capital Requirements Total capital requirements include construction expenditures as well as other major capital requirements and cash dividend requirements for both common and preferred stock. The main focus of the Company's construction program is upgrading generation systems, upgrading and expanding the electric and gas transmission and distribution systems and purchasing nuclear fuel. In addition, the Company anticipates significant expenditures to expand its wholesale generation capabilities. Projections for total capital requirements for 2002 are $409 million and projections for construction expenditures for 2002 are $391 million. For 2002-2006 projections, total capital requirements are $1.9 billion and construction expenditures are $1.8 billion, including the combustion turbines discussed below. These estimates are under continuing review and subject to on-going adjustment. The Company has committed to purchase five combustion turbines at a total cost of $151.3 million. The turbines for three planned power generation plants with a combined capacity of 657 MWs.The estimated cost of construction of the plants is approximately $400.3 million. The Company has expended $103.4 million as of December 31, 2001. In November 2001, the Company broke ground for Afton Generating Station ("Afton"), a 135 MW natural gas fired generating plant on a site in Southern New Mexico. This facility is expected to be operational by October 2002. Currently, the Company plans to expand the facility to 225 MW by the end of 2003. In February 2002, the Company also broke ground to build Lordsburg Generating Station ("Lordsburg"), an 80 MW natural gas fired generating plant in Southwestern New Mexico. This facility is expected to be operational by July 2002. The planned plants are part of the Company's ongoing competitive strategy of increasing generation capacity over time. The costs of these plants are not anticipated to be added to the rate base. 55 The Company's construction expenditures for 2001 were entirely funded through cash generated from operations. To meet its capital needs for its planned expansion of its generation capabilities, the Company expects that it will have to access the capital markets. Otherwise, the Company anticipates that internal cash generation and current debt capacity will be sufficient to meet all its other capital requirements for the years 2002 through 2006. To cover the difference in the amounts and timing of cash generation and cash requirements, the Company intends to use short-term borrowings under its liquidity arrangements. Liquidity At March 1, 2002, PNM had $170 million of available liquidity arrangements, consisting of $150 million from an unsecured revolving credit facility ("Credit Facility"), and $20 million in local lines of credit. The Credit Facility will expire in March 2003. There were $75.0 million in borrowings as of March 1, 2002. In addition, the Holding Company has a $20 million reciprocal borrowing agreement with PNM and $25 million in local lines of credit. The Company's ability to finance its construction program at a reasonable cost and to provide for other capital needs is largely dependent upon its ability to earn a fair return on equity, results of operations, credit ratings, regulatory approvals and financial and wholesale market conditions. Financing flexibility is enhanced by providing a high percentage of total capital requirements from internal sources and having the ability, if necessary, to issue long-term securities, and to obtain short-term credit. PNM's credit outlook is considered positive by Moody's Investor Services ("Moody's") and Fitch Ratings ("Fitch") and stable by Standard and Poors ("S&P"). Previously, in connection with PNM's announcement of its agreement to acquire Western Resources' electric utility operations, S&P, Moody's and Fitch placed PNM's securities ratings on negative credit watch pending review of the transaction. As a result of events which led the Company to conclude the acquisition could not be accomplished, ultimately leading the Company to terminate the transaction in January 2002, S&P, Moody's and Fitch removed the Company from negative credit watch. The Company is committed to maintaining its investment grade. S&P currently rates PNM's senior unsecured notes ("SUNs") and its Eastern Interconnection Project ("EIP") senior secured debt "BBB-" and its preferred stock "BB". Moody's rates PNM's SUNs and senior unsecured pollution control revenue bonds "Baa3"; and preferred stock "Ba1". The EIP senior secured debt is also rated "Ba1". Fitch rates PNM's SUNs and senior unsecured pollution control revenue bonds "BBB-," PNM's EIP lease obligation "BB+" and PNM's 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. 56 Long-term Obligations and Commitments The following table shows PNM's long-term debt and operating leases as of December 31, 2001. As of March 1, 2002, the Holding Company has no long-term obligations except those consolidated with PNM.
Payments Due ------------------------------------------------------------------ (In thousands) Contractual Less than After 5 Obligations Total 1 year 2-3 years 4-5 years years ------------ ------------ ----------- ----------- ------------ Long-Term Debt.................... 953,884 - - 268,420 685,464 Operating Leases.................. 532,954 32,095 66,162 70,356 364,341 ------------ ------------ ----------- ----------- ------------ Total Contractual Cash Obligations.................... 1,486,838 32,095 66,162 338,776 1,049,805 ============ ============ =========== =========== ============
PNM leases interests in Units 1 and 2 of PVNGS, certain transmission facilities, office buildings and other equipment under operating leases. The lease expense for PVNGS is $66.3 million per year over base lease terms expiring in 2015 and 2016. In 1998, PNM established PVNGS Capital Trust ("Capital Trust") for the purpose of acquiring all the debt underlying the PVNGS leases. PNM consolidates Capital Trust in its consolidated financial statements. The purchase was funded with the proceeds from the issuance of $435 million of SUNs, which were loaned to Capital Trust. Capital Trust then acquired and now holds the debt component of the PVNGS leases. For legal and regulatory reasons, the PVNGS lease payment continues to be recorded and paid gross with the debt component of the payment returned to PNM via Capital Trust. As a result, the net cash outflows for the PVNGS lease payment were $12.4 million in 2001. The table above reflects the net lease payment. PNM's other significant operating lease obligations include the Eastern Interconnect Project ("EIP"), a transmission line with annual lease payments of $7.3 million and a power purchase agreement for the entire output of Delta Persons Generating Station ("Delta"), a gas-fired generating plant in Albuquerque, New Mexico with imputed annual lease payments of $6.0 million. The Company's off-balance sheet obligations are limited to PNM's operating leases and certain financial instruments related to the purchase and sale of energy (see below). The present value of PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and the Delta PPA was $224 million as of December 31, 2001. PNM has entered various long-term power purchase agreements obligating it to make aggregate fixed payments of $30.3 million plus the cost of production and a return. These contracts expire December 2006 through July 2010. In addition, PNM is obligated to sell electricity for $158.1 million in fixed payments plus the cost of production and a return. These contracts expire December 2003 through June 2010. PNM's trading portfolio as of December 31, 2001 included open contract positions to buy $66.9 million of electricity and to sell $25.7 million of electricity. In addition, PNM had open contract positions classified as normal sales of electricity under the derivative accounting rules of $48.9 million and normal purchases of electricity of $8.1 million. 57 PNM has a coal supply contract for the needs of San Juan Generating Station ("SJGS") until 2017. The contract contemplates the delivery of approximately 103 million tons of coal during its remaining term. The pricing is based on the cost of extraction plus a margin. PNM contracts for the purchase of gas to serve its jurisdictional customers. These contracts are short-term in nature supplying the gas needs for the current heating season and the following off-season months. The price of gas is a pass-through, whereby the Company recovers 100% of its cost of gas. Contingent Provisions of Certain Obligations The Holding Company and PNM have a number of debt obligations and other contractual commitments that contain contingent provisions. Some of these, if triggered, could affect the liquidity of the Company. The Holding Company and/or PNM could be required to provide security, immediately pay outstanding obligations or be prevented from drawing on unused capacity under certain credit agreements, if the contingent requirements were to be triggered. The most significant consequences resulting from these contingent requirements are detailed in the discussion below. PNM's master purchase agreement for the procurement of gas for its jurisdictional customers contains a contingent requirement that could require PNM to provide security for its gas purchase obligations if the seller were to reasonably believe that PNM was unable to fulfill its payment obligations under the agreement. The master agreement for the sale of electricity in the Western System Power Pool ("WSPP") contains a contingent requirement that could require PNM to provide security if its' debt were to fall below the investment grade rating. The WSPP agreement also contains a contingent requirement, commonly called a material adverse change ("MAC") provision, which could require PNM to provide security if a material adverse change in its financial condition or operations were to occur. PNM's committed Credit Facility contains a MAC provision which if triggered could prevent PNM from drawing on its unused capacity under the Credit Facility. In addition, the Credit Facility contains a contingent requirement that requires PNM to maintain a debt-to-capital ratio of less than 70%. If PNM's debt-to-capital ratio were to exceed 70%, PNM could be required to repay all borrowings under the Credit Facility, be prevented from drawing on the unused capacity under the Credit Facility, and be required to provide security for all outstanding letters of credit issued under the Credit Facility. At December 31, 2001, the Company had $6.3 million of letters of credit outstanding. If a contingent requirement were to be triggered under the Credit Facility resulting in an acceleration of the outstanding loans under the Credit Facility, a cross-default provision in the PVNGS leases could occur if the accelerated amount is not paid. If a cross-default provision is triggered, the lessors have the ability to accelerate their rights under the leases, including acceleration of all future lease payments. Planned Financing Activities PNM has $268.4 million of long-term debt that matures in August 2005. All other long-term debt matures in 2016 or later. The Company could enter into other long-term financings for the purpose of strengthening its balance sheet, funding growth and reducing its cost of capital. The Company continues to evaluate its investment and debt retirement options to optimize its financing strategy and earnings potential. No additional first mortgage bonds may be issued under PNM's mortgage. The amount of SUNs that may be issued is not limited by the SUNs indenture. However, debt-to-capital requirements in certain of PNM's financial instruments would ultimately limit the amount of SUNs PNM would issue. PNM currently has $182.0 million of tax-exempt bonds outstanding that are callable at a premium in December 2002 and August 2003. PNM intends to refinance these bonds assuming the interest rate of the refinancing does not exceed the current interest rate and has hedged the entire planned refinancing. In order to 58 take advantage of current low interest rates, PNM entered into two forward starting interest rate swaps in November and December 2001 and three additional contracts subsequent to December 31, 2001. PNM designated these swaps as cash flow hedges. The hedged risks associated with these instruments are the changes in cash flows related to general moves in interest rates expected for the refinancing. The swaps effectively cap the interest rate on the refinancing to 4.9% plus an adjustment for PNM's and industry's credit rating. PNM's assessment of hedge effectiveness is based on changes in the hedge interest rates. The derivative accounting rules, as amended, provide that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transactions affect earnings. Any hedge ineffectiveness is required to be presented in current earnings. There was no material hedge ineffectiveness in the year ended December 31, 2001. A forward starting swap does not require any upfront premium and captures changes in the corporate credit component of an investment grade company's interest rate as well as the underlying Treasury benchmark. The five forward starting interest rate swaps have termination dates and notional amounts as follows: one with a termination date of September 17, 2002 for a notional amount of $46.0 million and four with a termination date of May 15, 2003 for a combined notional amount of $136.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transaction is cash settled on the mandatory unwind date (strike date), corresponding to the refinancing date of the underlying debt. The settlement will be capitalized as a cost of issuance and amortized over the life of the debt as a yield adjustment. If the hedged corporate interest rate along with the underlying benchmark were to decline below the capped level of the hedge, PNM will have to pay to settle the forward starting swap but would be able to issue the refinanced debt at the lower interest rate. However, if the hedged corporate interest rate along with the underlying benchmark were to decline but the interest rates available to PNM at the time of refinancing are greater than the existing rate of the debt to be refinanced due to credit issues, PNM will incur a loss on the hedge and not refinance the debt. Stock Repurchase In March 1999, PNM's Board of Directors approved a plan to repurchase up to 1,587,000 shares of its outstanding common stock with maximum purchase price of $19.00 per share. In December 1999, PNM Board of Directors authorized PNM to repurchase up to an additional $20.0 million of its common stock. As of December 31, 1999, PNM repurchased 1,070,700 shares of its previously outstanding common stock at a cost of $18.8 million. From January 2000 through March 2000, PNM repurchased an additional 1,167,684 shares of its outstanding common stock at a cost of $18.8 million. 59 On August 8, 2000, PNM's Board of Directors approved a plan to repurchase up to $35.0 million of its outstanding common stock through the end of the first quarter of 2001. From August 8, 2000 through December 31, 2000, PNM repurchased an additional 417,900 shares of its outstanding common stock at a cost of $9.0 million. The total cost of stock repurchased for the year ended December 31, 2000 was $27.9 million. There were no repurchases of common stock during the year ended December 31, 2001. The Board of Directors has authorized additional stock repurchases but the Company has not exercised that new authority. Dividends The Company's Board of Directors reviews the Company's dividend policy on a continuing basis. The declaration of common dividends is dependent upon a number of factors including the ability of the Company's subsidiaries to pay dividends. Currently, PNM is the Company's primary source of dividends. As part of the order approving the formation of the holding company, the PRC placed certain restrictions on the ability of PNM to pay dividends to its parent. The PRC order imposed the following conditions regarding dividends paid by PNM to the holding company: PNM can not pay dividends which cause its debt rating to go below investment grade; and PNM can not pay dividends in any year, as determined on a rolling four quarter basis, in excess of net earnings without prior PRC approval. Additionally, PNM has various financial covenants which limit the transfer of assets, through dividends or other means. In addition, the ability of the Company to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, its financial circumstances and performance, the PRC's decisions in various regulatory cases currently pending and which may be docketed in the future, the effect of deregulating generation markets and market economic conditions generally. The ability to recover stranded costs in deregulation (as amended), conditions imposed on holding company formation, future growth plans and the related capital requirements and standard business considerations may also affect the Company's ability to pay dividends. Consistent with the PRC's holding company order, PNM paid dividends of $127.0 million to the Company on December 31, 2001. On March 4, 2002, the PNM Board of Directors declared an additional dividend of approximately $5.5 million, which was paid March 19, 2002. On February 19, 2002, the Company's Board of Directors approved a 10 percent increase in the common stock dividend. The increase raises the quarterly dividend to $0.22 per share, for an indicated annual dividend of $0.88 per share. The Company's Board of Directors approved a policy for future dividend increases in the range of 8 to 10 percent annually, targeting a payout of between 50 to 60 percent of regulated earnings. The Company believes that this target is consistent with the Company's expectation of future operating cash flows and the cash needs of its planned increase in generating capacity. 60 Capital Structure The Company's capitalization, including current maturities of long-term debt, at December 31 is shown below: 2001 2000 --------- --------- Common Equity....................... 50.8% 48.6% Preferred Stock..................... 0.6 0.7 Long-term Debt...................... 48.6 50.7 --------- --------- Total Capitalization*............ 100.0% 100.0% ========= ========= *Total capitalization does not include as debt the present value of PNM's operating lease obligations for PVNGS Units 1 and 2, EIP and the Delta PPA which was $224 million as of December 31, 2001 and $227 million as of December 31, 2000. OTHER ISSUES FACING THE COMPANY RESTRUCTURING THE ELECTRIC UTILITY INDUSTRY In April 1999, New Mexico's Electric Utility Industry Restructuring Act of 1999 (the "Restructuring Act") was enacted into law. The Restructuring Act opens the state's electric power market to customer choice. In March 2001, amendments to the Restructuring Act were passed which delay the original implementation dates by approximately five years, including the requirement for corporate separation of supply service and energy-related service assets from distribution and transmission service assets. In addition, the PRC will have the authority to delay implementation for another year under certain circumstances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to choose among competing power suppliers beginning in January 2007. Competition would be expanded to include all customers starting in July 2007. The Company is unable to predict the form its further restructuring will take under the delayed implementation of customer choice. In addition, the Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers. The amendments to the Restructuring Act required that the PRC approve a holding company, subject to terms and conditions in the public interest, without corporate separation of supply service and energy-related service assets from distribution and transmission service assets, by July 1, 2001. In addition, the amendments allow utilities to engage in unregulated power generation business activities until corporate separation is implemented. On December 31, 2001, the Company implemented the holding company structure without corporate separation of supply service and energy-related services assets from distribution and transmission services assets. This structure provides for a holding company whose current holdings will be PNM, Avistar and other inactive unregulated subsidiaries. This was effected through the share exchange between PNM shareholders and the holding company, PNM Resources. Avistar and most of the inactive unregulated subsidiaries became wholly-owned subsidiaries of the holding company in January 2002. The transfer of certain corporate related assets to the holding company also occurred in January 2002. There are no current plans to provide the holding company with significant debt financing. 61 The 2002 session of the New Mexico Legislature resulted in enactment of tax measures favorable to the construction of merchant generating plants and plants fueled by renewable resources. The new laws provide authority for all local governments in the state to issue industrial revenue bonds for merchant generating plants smaller than 300 MW. The bonds provide exemptions from property taxes. Also enacted into law was a 5% investment tax credit for merchant generating plants smaller than 300 MW; tax credits for qualified generators using renewable resources; and an exemption from gross receipts tax for the cost of certain wind generation equipment. There is a growing concern in New Mexico about the use of water for merchant power plants, due to the increased activity in building these plants in the state, which has an arid climate. The availability of sufficient water supplies to meet all the needs of the state, including growth, is a major issue. It is expected that the Legislature will appoint an interim committee to study the impact of power plants on the state's water and other natural resources, with a report to be issued for the 2003 session. In building the Afton and Lordsburg plants, which are much smaller than other merchant plants under construction or planned by other generating companies, the Company has secured sufficient water rights. Congress is currently considering a number of bills affecting the energy industry, including comprehensive energy policy legislation that addresses numerous electricity issues that are fundamental to the structure of the industry. Among the provisions being considered are: granting FERC jurisdiction over currently non-jurisdictional entities for transmission; granting FERC authority to require participation in Regional Transmission Organizations ("RTO"); reliability standards; transmission pricing and siting; Public Utility Holding Company Act repeal; Public Utility Regulatory Policies Act repeal; net metering requirements; additional consumer protections; and renewable energy requirements. In addition, proposed tax legislation contains provisions relating to electric industry restructuring, primarily directing the Treasury Department, in consultation with FERC, to conduct a study of tax issues resulting from restructuring and to report to Congress annually. The tax legislation being considered also contains provisions regarding tax credits for electricity production from renewable resources, clean coal technologies and fuel cells, as well as tax incentives for energy conservation and efficiency measures. On March 8, 2002, the Senate passed the Economic Stimulus Package previously passed by the House of Representatives. The Package includes an extension to the federal production tax credit until January 1, 2004. The President is expected to sign the Package into law. The Company will continue to participate in the debate regarding national energy policy and any legislation affecting the industry. 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. The Company along with other Southwest transmission owners formed an RTO and made a filing on October 16, 2001 with the FERC. The FERC has indicated its intention to initiate a separate Notice of Proposed Rulemaking that would require implementation of new Open Access Transmission Tariffs by RTOs and by public utilities that own, operate, or control interstate transmission facilities. The new tariffs would adopt provisions to implement new transmission services and a standardized wholesale market design. The new functions would be implemented by an independent entity, which could be an RTO, that would perform services under the standard market design under rules applicable to all transmission customers. 62 RECOVERY OF CERTAIN COSTS UNDER THE RESTRUCTURING ACT Stranded Costs The Restructuring Act, as amended, recognizes that electric utilities should be permitted a reasonable opportunity to recover an appropriate amount of the costs previously incurred in providing electric service to their customers. These stranded costs represent all costs associated with generation-related assets, currently in rates, in excess of the expected competitive market price over the life of those assets and include plant decommissioning costs, regulatory assets, and lease and lease-related costs. Utilities will be allowed to recover no less than 50% of stranded costs through a non-bypassable charge on all customer bills for five years after implementation of customer choice. The PRC could authorize a utility to recover up to 100% of its stranded costs if the PRC finds that recovery of more than 50%: (i) is in the public interest; (ii) is necessary to maintain the financial integrity of the public utility; (iii) is necessary to continue adequate and reliable service; and (iv) will not cause an increase in rates to residential or small business customers during the transition period. The Restructuring Act, as amended, also allows for the recovery of nuclear decommissioning costs by means of a separate wires charge over the life of the underlying generation assets (see Nuclear Regulatory Commission Prefunding below). The calculation of stranded costs is subject to a number of highly sensitive assumptions, including the date of open access, appropriate discount rates and projected market prices, among others. The Restructuring Act, as amended, requires the Company to file a transition plan which includes provisions for the recovery of stranded costs and other expenses associated with the transition to a competitive market no later than January 1, 2005. The Company is unable to predict the amount of stranded costs that it may seek to recover at that time. The Company's previous proposal to recover its stranded costs under the original customer choice implementation dates would not accurately represent the Company's expected stranded costs under the amended implementation dates of the Restructuring Act. Approximately $142 million of costs associated with the power supply and energy services businesses under the Restructuring Act were established as regulatory assets. Because of the Company's belief that recovery is probable, these assets continue to be classified as regulatory assets, although the Company has discontinued the use of accounting for rate regulated activities. The amendments to the Restructuring Act provide the opportunity for amortization of coal mine decommissioning costs currently estimated at approximately $100 million. The Company intends to seek recovery of these costs in its next rate case filing and believes that the costs are fully recoverable. The Company believes that any remaining portion of the regulatory assets will be fully recovered in future rates, including through a non-bypassable wires charge. The Company believes that the Restructuring Act, as amended, if properly applied, provides an opportunity for recovery of a reasonable amount of stranded costs should such costs exist at the time of separation. If regulatory orders do not provide for a reasonable recovery, the Company is prepared to vigorously pursue judicial remedies. The PRC will make a determination and quantification of stranded cost recovery prior to implementation of restructuring. The determination may have an impact on the recoverability of the related assets and may have a material effect on the future financial results and position of the Company. 63 Transition Cost Recovery In addition, the Restructuring Act, as amended, authorizes utilities to recover in full any prudent and reasonable costs incurred in implementing full open access ("transition costs"). These transition costs are currently scheduled to be recovered from 2007 through 2012 by means of a separate wires charge. The PRC may extend this date by up to one year. The Company may seek to recover transition costs already incurred in future rate cases that may occur prior to open access. The Company is unable to predict the amount of transition costs it may incur. To date, the Company has capitalized $24.3 million of expenditures that meet the Restructuring Act's definition of transition costs. Transition costs for which the Company will seek recovery include professional fees, financing costs, consents relating to the transfer of assets, management information system changes including billing system changes and public and customer education and communications. These costs will be amortized over the recovery period to match related revenues. The Company intends to vigorously pursue remedies available to it should the PRC disallow recovery of reasonable transition costs. Costs not recoverable will be expensed when incurred unless these costs are otherwise permitted to be capitalized under current and future accounting rules. Depending on the amount of non-recoverable transition costs, if any, the resulting charge to earnings may have a material effect on the future financial results and position of the Company. Nuclear Regulatory Commission ("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. The NRC rules on financial assurance became effective on November 23, 1998. The amended rules provide that a licensee may use an external sinking fund as the exclusive financial assurance mechanism if the licensee recovers estimated decommissioning costs through cost of service rates or a "non-bypassable charge". Other mechanisms are prescribed, such as prepayment, surety methods, insurance and other guarantees, to the extent that the requirements for exclusive reliance on the fund mechanism are not met. The Restructuring Act, as amended, allows for the recoverability of 50% up to 100% of stranded costs including nuclear decommissioning costs. The results of the 1998 triannual decommissioning cost study indicated that PNM's share of the PVNGS decommissioning costs excluding spent fuel disposal will be approximately $181 million (in 1998 dollars). The Restructuring Act, as amended, specifically identifies nuclear decommissioning costs as eligible for separate recovery over a longer period of time than other stranded costs if the PRC determines a separate recovery mechanism to be in the public interest. In addition, the Restructuring Act, as amended, states that it does not require the PRC to issue any order which would result in loss of eligibility to exclusively use external sinking fund methods for decommissioning obligations pursuant to Federal regulations. When final determination of stranded cost recovery is made and if the Company is unable to meet the requirements of the NRC rules permitting the use of an external sinking fund because it is unable to recover all of its estimated decommissioning costs through a non-bypassable charge, the Company may have to pre-fund or find a similarly capital intensive means to meet the NRC rules. There can be no assurance that such an event will not negatively affect the funding of the Company's growth plans. 64 MERCHANT PLANT FILING Senate Bill ("SB") 266, enacted by the 2001 session of the New Mexico legislature, allowed public utilities to "invest in, construct, acquire or operate" a generating plant not intended to provide retail electric service, free of certain otherwise applicable regulatory requirements contained in the Public Utility Act. By order entered on March 27, 2001, the PRC found that these provisions of SB 266 raised issues such as cost allocations for ratemaking, revenue allocations for off-system sales, how the Commission can ensure the utility will meet its duty to provide service when the utility invests in such generating plant, how that plant will be financed and how transactions between regulated services and merchant plants will be conducted. The Company has filed a pleading addressing these issues and testimony in response to interested parties' requests. The PRC has established a schedule for the filing of staff and intervenor testimony and for the Company's rebuttal testimony, culminating in a hearing scheduled for June 10, 2002. In November 2001, the Company began settlement negotiations with the PRC's utility staff and intervenors related to these PRC proceedings in order to resolve a number of matters. In addition to the issues being examined in the Company's merchant plant filing, discussions have included the future framework for restructuring the electric industry in New Mexico under the Restructuring Act, and a future retail electric rate path. The negotiations include the potential implementation and effective date of rates that would replace those approved under the rate freeze stipulation that remains in effect until January 1, 2003. The Company is currently unable to predict the impact these proceedings may have on its plans to expand its generating capacity and other operations. WESTERN UNITED STATES WHOLESALE POWER MARKET A significant portion of the Company's earnings in 2001 was derived from the Company's wholesale power trading operations, which benefited from strong demand and high wholesale prices in the Western United States. These market conditions were primarily driven by the electric power supply shortages in the Western United States during the first half of the year. As a result of the supply imbalance, the wholesale power market in the Western United States became extremely volatile and, while providing many marketing opportunities, presented and continues to present significant risk to companies selling power into this marketplace. Moderate weather in California, as well as certain regulatory actions (see below), have caused a significant decline in the price of wholesale electricity in the Western United States wholesale power market. In addition, conservation measures and new generation have or are expected to put downward pressure on wholesale electricity prices. As a result of these trends, the Company expects its earnings from wholesale power trading operations to be significantly lower in the future than the levels seen during the last half of 2000 and the first half of 2001. The power market in the Western United States has been the subject of widespread national attention. At the heart of the situation were flaws in the California deregulation legislation and a significant imbalance between electric supply and demand. These circumstances were aggravated by other factors such as increases in gas supply costs, weather conditions and transmission constraints. 65 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 put significant downward pressure on wholesale prices. The Company cannot predict the ultimate outcome of these governmental initiatives and their long-term effect on the Western United States power market or on the Company's ability to market into the California market. During 2001, regional wholesale electricity prices reached over $1,000 per MWh mainly due to the electric power shortages in the West although current price levels are much depressed from this level. Two of California's major utilities, Southern California Edison Company ("SCE") and Pacific Gas and Electric Co. ("PG&E"), were unable to fully recover their wholesale power costs from their retail customers. As a result, both utilities experienced severe liquidity constraints. PG&E decided to seek bankruptcy protection while SCE was 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 these markets be capped at $150 per MWh unless the seller could demonstrate that its costs exceeded the cap. This price cap was effectively modified by FERC orders issued in March and April 2001 that directed certain power suppliers to provide refunds for overcharges calculated on the basis of a formula that sanctioned wholesale prices considerably in excess of the $150 per MWh level. On April 26, 2001, the FERC adopted an order establishing prospective mitigation and a monitoring plan for the California wholesale markets and which established a further investigation of public utility rates in wholesale Western energy markets. The plan reflected in the April 26 order, replaced the $150 per MWh soft cap previously established and applied during periods of system emergency. Thereafter, on June 19, 2001, the FERC issued still another order that changed the previous orders and expanded the price mitigation approach of the April 26 order to all of the Western region. As a result of the price mitigation plan and other factors, such as moderate weather in California and lower gas prices, wholesale electric prices declined significantly by the end of the third quarter and remained low through the fourth 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 were due resulting from wholesale sales into the Pacific Northwest. The Pacific Northwest matter was heard by an administrative law judge whose recommended decision declined to order refunds resulting from sales into the Pacific Northwest, but the FERC has not yet acted on this recommended decision. The hearing on potential California refund obligations has not yet been completed and a recommended decision is not anticipated until the second half of 2002. The Company is unable to predict the ultimate outcome of these FERC proceedings, or whether the Company will be directed to make any refunds as the result of a FERC order. 66 In 2001, approximately $2 million in wholesale power sales by the Company were made directly to the Cal PX, which was the main market for the purchase and sale of electricity in the state in the beginning of 2001, or the Cal ISO which manages the state's electricity transmission network. In January and February 2001, SCE and PG&E, major purchasers of power from the Cal PX and ISO, defaulted on payments due the Cal PX for power purchased from the Cal PX in 2000. These defaults caused the Cal PX to seek bankruptcy protection. The Company has filed its proofs of claims in the Cal PX and PG&E bankruptcy proceedings. Total amounts due from the Cal PX or Cal ISO for power sold to them in 2000 and 2001 total approximately $7 million. The Company has provided allowances for the total amount due from the Cal PX and Cal ISO. Prior to its bankruptcy filing, the Cal PX undertook to charge back the defaults of SCE and PG&E to other market participants, in proportion to their participation in the markets. The Company was invoiced for $2.3 million as its proportionate share under the Cal PX tariff. The Company, as well as a number of power marketers and generators, filed complaints with the FERC to halt the Cal PX's attempt to collect these payments under the charge-back mechanism, claiming the mechanism was not intended for these purposes, and even if it was so intended, such an application was unreasonable and destabilizing to the California power market. The FERC 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 this funding would be replaced with the issuance of revenue bonds by the state. In the first quarter of 2001, the Company began to sell power to the Cal DWR. The Company has regularly monitored its credit risk with regard to its Cal DWR sales and believes its exposure is prudent. In addition to sales directly to California, the Company sells power to customers in other jurisdictions who sell to California and whose ability to pay the Company may be dependent on payment from California. The Company is unable to determine whether its non-California power sales ultimately are resold in the California market. The Company's credit risk is monitored by its Risk Management Committee, which is comprised of senior finance and operations managers. The Company seeks to minimize its exposure through established credit limits, a diversified customer base and the structuring of transactions to take advantage of off-setting positions with its customers. To the extent these customers who sell power into California are dependent on payment from California to make their payments to the Company, the Company may be exposed to credit risk which did not exist prior to the California situation. In 2001, in response to the increased credit risk and market price volatility described above, the Company provided an additional allowance against revenue of $3.5 million for anticipated losses to reflect management's estimate of the increased market and credit risk in the wholesale power market and its impact on 2001 revenues. Based on information available at December 31, 2001, the Company believes the total allowance for anticipated losses, currently established at $12.0 million, is adequate for management's estimate of potential uncollectible accounts. The Company will continue to monitor the wholesale power marketplace and adjust its estimates accordingly. 67 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. The California Attorney General has filed a lawsuit against certain power marketers for alleged unfair trade practices involving the reselling of reserved capacity. The Company is not one of the named defendants. 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 been forced to consider a bankruptcy filing. However, at the present time such a bankruptcy filing does not appear likely, given the understanding that SCE has refinanced a significant portion of its outstanding debt and cured many previously existing payment defaults under its debt agreements and also with the Cal PX and other suppliers. SCE is a 15.8% participant in PVNGS and a 48.0% participant in Four Corners. Pursuant to an agreement among the participants in PVNGS and an agreement among the participants in Four Corners Units 4 and 5, each participant is required to fund its proportionate share of operation and maintenance, capital, and fuel costs of PVNGS and Four Corners Units 4 and 5. The Company estimates SCE's total monthly share of these costs to be approximately $7.8 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. TERMINATION OF WESTERN RESOURCES TRANSACTION On November 9, 2000, PNM and Western Resources announced that both companies' Boards of Directors approved an agreement under which PNM would acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing. 68 In July 2001, the KCC issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for a $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger. Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001, in New York state court seeking declarations that the transaction could not be accomplished as designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. On November 19, 2001, Western Resources filed a complaint against the Company in New York state court alleging breach of contract and breach of implied covenant of good faith and fair dealing. Western Resources alleged that the Company brought about the KCC orders, failed to assist in efforts to reverse the KCC orders, refused to renegotiate within the terms of the agreement, interfered with Western Resources' efforts to satisfy the terms of the agreement, and effected an unauthorized de facto termination of the agreement by filing its complaint. Western Resources alleges damages in excess of $650 million. The Company believes that the complaint filed by Western Resources is without merit and intends to vigorously defend itself against the complaint. The Company also intends to vigorously pursue its own complaint. On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. On February 5, 2002, the District Court for Shawnee County, Kansas, dismissed without prejudice Western Resources' petition for judicial review of the KCC's split-off orders. The Court ruled that by filing a new financial plan in compliance with the orders, Western Resources accepted certain portions of the orders thereby creating a situation where further administrative action became necessary. As a result, the Court concluded that the matter was not ripe for judicial review and remanded the case to the KCC. On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate order. The Company is currently unable to predict the outcome of its litigation with Western Resources. 69 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. Based upon information available at December 31, 2001, the Company believes the allowance for doubtful accounts of $7.7 million is adequate for management's estimate of potential uncollectible accounts. The following is a summary of the allowance for doubtful accounts for the Utility Operations which utilizes the customer billing system during 2001, 2000 and 1999:
2001 2000 1999 ------------- ------------- ------------ (In thousands) Allowance for doubtful accounts, beginning of year................................................. $7,550 $12,504 $ 836 Bad debt expense.......................................... 5,682 8,567 11,496 Less: Write off (adjustments) of uncollectible accounts.. 5,566 13,521 (172) ------------- ------------- ------------ Allowance for doubtful accounts, end of year ............. $7,666 $7,550 $12,504 ============= ============= ============
Note: Above schedule excludes bad debt allowance for the Generation and Trading Operations 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"). In 2001, FERC issued a "proposed" order directing the Company to provide transmission service, but left the terms of service to be negotiated by the parties and subject to final FERC review and determination. In January 2002, the parties submitted a settlement agreement resolving most of the issues relating to the rates, terms and conditions of service. The "proposed" FERC order is not 70 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 Company is evaluating its legal options in relation to the "proposed" order or any resulting "final" order. The settlement agreement reserves the Company's rights to seek rehearing and judicial review of any final order and to present other legal claims. In February 2002, the FERC administrative law judge who supervised the negotiations leading to the partial settlement recommended that FERC issue a final order approving the agreement. A related PRC proceeding has been stayed, pending the outcome of the FERC case. The effect of the FERC's proposed 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 believes that the impact will be immaterial based on the facts above. COAL FUEL SUPPLY In 1996, the Company was notified by San Juan Coal Company ("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. On November 6, 2001, an administrative order was issued denying the proposed selections. The Company is monitoring an appeal by the Navajo Nation and other developments on this issue and will continue to assess, but cannot estimate with any certainty the potential impacts to the SJGS and the Company's operations. 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 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. 71 The nature and cost of the impacts of EPA's changed interpretation of the application of the NSR and NSPS, together with proposed changes to these regulations, may be significant to the power production industry. However, the Company cannot quantify these impacts with regard to its power plants. It is also not yet known what changes in EPA policy, if any, may occur in the NSR area as a result of the change in administration in Washington. The National Energy Policy released May 2001 by the National Energy Policy Development Group, called for a review of the pending NSR enforcement actions and that review continues by the EPA. If the EPA should prevail with its current interpretation of the NSR and NSPS rules, the Company may be required to make significant capital expenditures which could have a material adverse effect on the Company's financial position and results of operations. Threatened Citizen Suit Under the Clean Air Act By letter dated January 9, 2002, counsel for the Grand Canyon Trust and Sierra Club (collectively, "GCT") notified the Company of GCT's intent to file a so-called "citizen suit" under the Clean Air Act, alleging that the Company and co-owners of the SJGS violated the Clean Air Act, and the implementing federal and state regulations, at SJGS. The notice indicates that penalties and injunctive relief may be sought. Under the Clean Air Act, GCT must wait at least 60 days after affording the Company notice (i.e., until March 9, 2002) before filing a lawsuit. The allegations contained in GCT's notice of intent to sue fall into three categories. First, GCT contends that the plant has violated, and is currently in violation, of the federal NSPS at all four units at SJGS. Second, GCT argues that the plant has violated, and is currently in violation, of the federal PSD rules, as well as the corresponding provisions of the New Mexico Administrative Code, at all four units. Third, GCT alleges that the plant has "regularly violated" the 20% opacity limit contained in SJGS's operating permit and set forth in federal and state regulations at Units 1, 3 and 4. The Company is currently investigating the allegations contained in the notice of intent to sue. Based on its investigation to date, the Company firmly believes that the allegations are without merit. By letter to GCT's counsel dated February 22, 2002, the Company vigorously disputed the allegations and affirmed its compliance with the laws in question. The Company adheres to high environmental standards as evidenced by its International Standards Organization ratings. In that letter, the Company also stated that the GCT has failed to provide sufficient information to permit full examination of the allegations. If a lawsuit is filed by GCT, as threatened, the Company will respond on behalf of the co-owners and vigorously defend in the litigation. The Company is, however, unable to predict the ultimate outcome of the matter. NATURAL GAS EXPLOSION On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The Company's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. The Company also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau which issued its report on March 18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the Company by the injured persons along with several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur as a result of the Pipeline Safety Bureau's investigation. There can be no assurance that the outcome of this matter will not have a material impact on the results of operations and financial position of the Company. 72 NAVAJO NATION TAX ISSUES Arizona Public Service Company ("APS"), the operating agent for Four Corners, has informed the Company that in March 1999, APS initiated discussions with the Navajo Nation regarding various tax issues in conjunction with the expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to the possessory interest tax and the business activity tax associated with the Four Corners operations on the reservation. The Company believes that the resolution of these tax issues will require an extended process and could potentially affect the cost of conducting business activities on the reservation. The Company is unable to predict the ultimate outcome of discussions with the Navajo Nation regarding these tax issues and cannot estimate with any certainty the potential impact on the Company's operations. LANDOWNER ENVIRONMENTAL CLAIMS 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. 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 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 73 scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position. DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS Statements made in this filing that relate to future events are made pursuant to the Private Securities Litigation Reform Act of 1995. Readers are cautioned that all forward-looking statements are based upon current expectations and are subject to risk and uncertainties. The Company assumes no obligation to update this information. Because actual results may differ materially from expectations, the Company cautions readers not to place undue reliance on these statements. A number of factors, including weather, fuel costs, changes in the local and national economy, changes in supply and demand in the market for electric power, the outcome of litigation relating to the Company's terminated transaction with Western Resources, the performance of generating units and transmission system, and state and federal regulatory and legislative decisions and actions, including the wholesale electric power pricing mitigation plan ordered by FERC on June 18, 2001, rulings issued by the PRC pursuant to the Electric Utility Industry Restructuring Act of 1999, as amended, and in other cases now pending or which may be brought before the FERC and the PRC and any action by the New Mexico Legislature to further amend or repeal that Act, or other actions relating to restructuring or stranded cost recovery, or federal or state regulatory, legislative or legal action connected with the California wholesale power market and wholesale power markets in the West, could cause the Company's results or outcomes to differ materially from those indicated by such forward-looking statements in this filing. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices, changes in interest rates and, historically, adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. Information about the Company's financial instruments is set forth in "Critical Accounting Policies" section of Management's Discussion of Results of Operations and Financial Condition and the Financial Instruments note in the Notes to the Consolidated Financial Statements and incorporated by reference. The following additional information is provided. Risk Management The Company controls the scope of its various forms of risk through a comprehensive set of policies and procedures and oversight by senior level management and the Board of Directors. The Company's Finance Committee of the Board of Directors sets the risk limit parameters. An internal risk management committee ("RMC"), comprised of corporate and business segment officers, oversees all of the activities, which include commodity price, credit, equity, interest rate and business risks. The RMC has oversight for the ongoing evaluation of the adequacy of the risk control organization and policies. The Company has a risk control organization, headed by the Director of Financial Risk Management ("Risk Manager"), which is assigned responsibility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions, on an enterprise-wide basis. 74 The RMC's responsibilities specifically include: establishment of a general policy regarding risk exposure levels and activities in each of the business units; recommendation of the types of instruments permitted for trading; authority to establish a general policy regarding counterparty exposure and limits; authorization and delegation of trading transaction limits for trading activities; review and approval of controls and procedures for the trading activities; review and approval of models and assumptions used to calculate mark-to-market and risk exposure; authority to approve and open brokerage and counterparty accounts for derivative trading; review for trading and risk activities; and quarterly reporting to the Finance Committee and the Board of Directors on these activities. The RMC also proposes Value at Risk ("VAR") limits to the Finance Committee. The Finance Committee ultimately sets the aggregate VAR limit. It is the responsibility of each business unit to create its own control and procedures policy for trading within the parameters established by the Finance Committee. The RMC reviews and approves these policies, which are created with the assistance of the Chief Accounting Officer, Director of Internal Audit and the Risk Manager. Each business units' policies address the following controls: authorized risk exposure limits; authorized trading instruments and markets; authorized traders; policies on segregation of duties; policies on marking to market; responsibilities for trade capture; confirmation procedures; responsibilities for reporting results; statement on the role of derivatives trading; and limits on individual transaction size (nominal value) for traders. To the extent an open position exists, fluctuating commodity prices can impact financial results and financial position, either favorably or unfavorably. As a result, the Company cannot predict with precision the impact that its risk management decisions may have on its businesses, operating results or financial position. Commodity Risk Trading and marketing operations often involve market risks associated with managing energy commodities and establishing open positions in the energy markets, primarily on a short-term basis. These risks fall into three different categories: price and volume volatility, credit risk of trading counterparties and adequacy of the control environment for trading. The company routinely enters into forward contracts and options to hedge purchase and sale commitments, fuel requirements and to minimize the risk of market fluctuations on the Generation and Trading Operations. The Company's wholesale power marketing operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. 75 The Company assesses the risk of these derivatives using the VAR method, in order to maintain the Company's total exposure within management-prescribed limits. The Company utilizes the variance/covariance model of VAR, which is a probabilistic model that measures the risk of loss to earnings in market sensitive instruments. The variance/covariance model relies on statistical relationships to analyze how changes in different markets can affect a portfolio of instruments with different characteristics and market exposure. VAR models are relatively sophisticated; however, the quantitative risk information is limited by the parameters established in creating the model. The instruments being evaluated may trigger a potential loss in excess of calculated amounts if changes in commodity prices exceed the confidence level of the model used. The VAR methodology employs the following critical parameters: volatility estimates, market values of open positions, appropriate market-oriented holding periods and seasonally adjusted correlation estimates. The Company uses a holding period of three days as the estimate of the length of time that will be needed to liquidate the positions. The volatility and the correlation estimates measure the impact of adverse price movements both at an individual position level as well as at the total portfolio level. The confidence level established is 99%. For example, if VAR is calculated at $10 million, it is estimated at a 99% confidence level that if prices move against the Company's positions, the Company's pre-tax gain or loss in liquidating the portfolio would not exceed $10 million in the three days that it would take to liquidate the portfolio. The Company accounts for the sale of its electric generation in excess of its jurisdictional needs or the purchase of jurisdictional needs as non-trading. Non-jurisdictional purchases for resale and subsequent resales are accounted for as energy trading contracts. With respect to the Company's trading portfolio, the VAR was $1.2 million. The Company calculates a portfolio VAR which in addition to its trading portfolio includes all non-trading designated contracts, its generation assets excluded from jurisdictional rates and any excess jurisdictional capacity. This excess is determined using average peak forecasts for the respective block of power in the forward market. The Company's portfolio VAR was $12.4 million at December 31, 2001. The Company's VAR is regularly monitored by the Company's RMC. The RMC has put in place procedures to ensure that increases in VAR are reviewed and, if deemed necessary, acted upon to reduce exposures. The VAR represents an estimate of the potential gains or losses that could be recognized on the Company's wholesale power marketing portfolio given current volatility in the market, and is not necessarily indicative of actual results that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ due to actual fluctuations in market rates, operating exposures, and the timing thereof, as well as changes to the Company's wholesale power marketing portfolio during the year. In addition, the Company is exposed to credit losses in the event of non-performance or non-payment by counterparties. The Company uses a credit management process to access and monitor the financial conditions of counterparties. Credit exposure is also regularly monitored by the RMC. The Company provides for losses due to market and credit risk. The Company's credit risk with its largest counterparty as of December 31, 2001 and 2000 was $7.5 million and $16.7 million respectively. 76 The Company hedges certain portions of natural gas supply contracts in order to protect its jurisdictional customers from adverse price fluctuations in the natural gas market. The financial impact of all hedge gains and losses, including the related costs of the program, is recoverable through the Company's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by gains and losses generated by these instruments. Interest Rate Risk As of December 31, 2001, the Company has an investment portfolio of fixed-rate government obligations and corporate securities which is subject to the risk of loss associated with movements in market interest rates. For accounting purposes, the portfolio is classified as available-for-sale and is marked-to-market. As a result, unrealized losses resulting from interest rate increases are recorded as a component of comprehensive income. If interest rates were to rise, 50 basis points from their levels at December 31, 2001, the fair value of these instruments would decline by 0.6% or $0.9 million. In addition, because of this interest rate sensitivity, early or unplanned redemption of these investments in a period of increasing interest rates would subject the Company to risk of a realized loss of principal as the fair market value of these investments would be less than their carrying value. The Company employs investment managers to mitigate this risk. As part of its investing strategies, the Company has diversified its portfolio with investments of varying maturity, obligors and limits credit exposure to high investment grade quality investments. The Company has long-term debt which subjects it to the risk of loss associated with movements in market interest rates. All of the Company's long-term debt is fixed-rate debt, and therefore, does not expose the Company's earnings to a risk of loss due to adverse changes in market interest rates. However, the fair value of these debts instruments would increase by approximately 1.8% or $17.6 million if interest rates were to decline by 50 basis points from their levels at December 31, 2001. As of December 31, 2001, the fair value of the Company's long-term debt was $974 million as compared to a book-value of $954 million. In general, an increase in fair value would impact earnings and cash flows if the Company were to re-acquire all or a portion of its debt instruments in the open market prior to their maturity. Certain issuances of the Company's debt have call dates in December 2002 and August 2003. To hedge against the risk of rising interest rates and their impact on the economies of calling the debt, the Company has entered into two forward starting swaps in 2001 and three additional contracts in 2002. These forward interest rate swaps effectively lock-in interest rates for the notional amount of the debt that is callable at a rate of approximately 4.9% plus an adjustment for the Company's and industry's credit rating. At December 31, 2001, the fair market value of these derivative financial instruments was approximately $2.0 million. The Company contributed $6.1 million in 2001 to a trust established to fund decommissioning costs for PVNGS. In January 2002, the Company contributed $23.5 million for plan year 2001 to the trust for the Company's pension plan, and other post retirement benefits. The securities held by the trusts had an estimated fair value of $461.5 million as of December 31, 2001, of which approximately 30% were fixed-rate debt securities that subject the Company to risk of loss of fair value with movements in market interest rates. If rates were to increase by 50 basis points from their levels at December 31, 2001, the decrease in the fair value of the securities would be 3.0% or $4.0 million. The Company does not currently recover or return in jurisdictional rates losses or gains on these securities; therefore, the Company is at risk for shortfalls in its funding of its obligations due to investment losses. However, the Company does not believe that long-term market returns over the period of funding will be less than required for the Company to meet its obligations. 77 Equity Market Risk As discussed above under Interest Rate Risk, the Company contributes to trusts established to fund its share of the decommissioning costs of PVNGS and other post retirement benefits. The trust holds certain equity securities as of December 31, 2001. These equity securities also expose the Company to losses in fair value. Approximately 60% of the securities held by the various trusts were equity securities as of December 31, 2001. Similar to the debt securities held for funding decommissioning and certain pension and other postretirement costs, the Company does not recover or return in jurisdictional rates losses or gains on these equity securities. In 2001, the Company implemented an enhanced cash management strategy using derivative instruments based on the Standard & Poors 100 and 500 indices. The strategy is designed to capitalize on high market volatility or benefit from market direction. An investment manager is utilized to execute the program. The program is carefully managed by the RMC and limited to a one-day VAR of $5 million and a loss limit of $7.5 million. Trades are closed-out before the end of a reporting period and typically within the same day of execution. Recently, the RMC recommended and the Finance Committee approved the use of derivatives based on the Nasdaq composite index. 78 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX Page ---- Management's Responsibility for Financial Statements................... F-1 Report of Independent Public Accountants............................... F-3 Financial Statements: PNM Resources, Inc. Consolidated Statements of Earnings............................. F-4 Consolidated Balance Sheets..................................... F-5 Consolidated Statements of Cash Flows........................... F-7 Consolidated Statements of Capitalization....................... F-8 Consolidated Statements of Comprehensive Income................. F-9 Public Service Company of New Mexico Consolidated Statements of Earnings............................. F-10 Consolidated Balance Sheets..................................... F-11 Consolidated Statements of Cash Flows........................... F-13 Consolidated Statements of Capitalization....................... F-14 Consolidated Statements of Comprehensive Income................. F-15 Notes to Consolidated Financial Statements ......................... F-16 Supplementary Data: Quarterly Operating Results......................................... F-53 Comparative Operating Statistics.................................... F-54 Report of Independent Public Accountants............................ F-56 Schedule I Condensed Financial Information of Parent Company........ F-57 Schedule II Valuation and Qualifying Accounts....................... F-59 MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTS The accompanying financial statements, of PNM Resources, Inc. and its subsidiaries and Public Service Company of New Mexico and its subsidiaries, a wholly owned subsidiary of PNM Resources, Inc. have been prepared in conformity with accounting principles generally accepted in the United States. The integrity and objectivity of data in these financial statements and accompanying notes, including estimates and judgments related to matters not concluded by year-end, are the responsibility of management as is all other information in this Annual Report. Management devotes ongoing attention to review and appraisal of its system of internal controls. This system is designed to provide reasonable assurance, at an appropriate cost, that PNM Resources, Inc.'s and Public Service Company of New Mexico's assets are protected, that transactions and events are recorded properly and that financial reports are reliable. The system is augmented by a staff of corporate auditors; careful attention to selection and development of qualified financial personnel; and programs to further timely communication and monitoring of policies, standards and delegated authorities. F-1 The Audit Committee of the Board of Directors of PNM Resources, Inc., composed entirely of outside directors, meets regularly with financial management, the corporate auditors and the independent auditors to review the work of each. The independent auditors and corporate auditors have free access to the Audit Committee, without management representatives present, to discuss the results of their audits and their comments on the adequacy of internal controls and the quality of financial reporting. F-2 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ---------------------------------------- To the Board of Directors and Stockholders of PNM Resources, Inc. and Public Service Company of New Mexico: We have audited the accompanying consolidated balance sheets and statements of capitalization of PNM Resources, Inc. (a New Mexico Corporation) and subsidiaries and Public Service Company of New Mexico and subsidiaries (a New Mexico Corporation) as of December 31, 2001 and 2000, and the related consolidated statements of earnings, cash flows and comprehensive income for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Companies' management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PNM Resources, Inc. and subsidiaries and Public Service Company of New Mexico and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Albuquerque, New Mexico February 1, 2002 F-3
PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS Year Ended December 31, --------------------------------------- 2001 2000 1999 ------------ ------------ ------------ (In thousands, except per share amounts) Operating Revenues: (note 1) Electric................................................... $1,965,142 $1,289,192 $ 911,977 Gas........................................................ 385,418 319,924 236,711 Unregulated businesses..................................... 1,538 2,158 8,855 ------------ ------------ ------------ Total operating revenues................................ 2,352,098 1,611,274 1,157,543 ------------ ------------ ------------ Operating Expenses: Cost of energy sold........................................ 1,536,566 949,880 531,952 Administrative and general................................. 155,392 147,268 153,709 Energy production costs.................................... 152,455 139,894 140,784 Depreciation and amortization.............................. 96,936 93,059 92,661 Transmission and distribution costs........................ 69,001 60,330 59,264 Taxes, other than income taxes............................. 30,302 34,405 34,084 Income taxes (note 7)...................................... 88,769 53,964 25,010 ------------ ------------ ------------ Total operating expenses................................ 2,129,421 1,478,800 1,037,464 ------------ ------------ ------------ Operating income........................................ 222,677 132,474 120,079 ------------ ------------ ------------ Other Income and Deductions: Other...................................................... (15,110) 54,296 47,500 Income tax expense (note 7)............................... 7,706 (20,382) (17,298) ------------ ------------ ------------ Net other income and deductions......................... (7,404) 33,914 30,202 ------------ ------------ ------------ Income before interest charges.......................... 215,273 166,388 150,281 ------------ ------------ ------------ Interest Charges: Interest on long-term debt (note 3)........................ 62,716 62,823 65,899 Other interest charges..................................... 2,124 2,619 4,768 ------------ ------------ ------------ Net interest charges.................................... 64,840 65,442 70,667 ------------ ------------ ------------ Net Earnings from Continuing Operations...................... 150,433 100,946 79,614 Cumulative Effect of a Change in Accounting.................. Principle, Net of Tax..................................... - - 3,541 ------------ ------------ ------------ Net Earnings................................................. 150,433 100,946 83,155 Preferred Stock Dividend Requirements........................ 586 586 586 ------------ ------------ ------------ Net Earnings Applicable to Common Stock...................... $ 149,847 $ 100,360 $ 82,569 ============ ============ ============ Net Earnings per Share of Common Stock (Basic) (note 6)...... $ 3.83 $ 2.54 $ 2.01 ============ ============ ============ Net Earnings per Share of Common Stock (Diluted) (note 6).... $ 3.77 $ 2.53 $ 2.01 ============ ============ ============ Dividends Paid per Share of Common Stock..................... $ 0.80 $ 0.80 $ 0.80 ============ ============ ============
The accompanying notes are an integral part of these financial statements. F-4 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS
As of December 31, ------------------------- 2001 2000 ----------- ------------ (In thousands) Utility Plant, at original cost except PVNGS: (notes 10, 11) Electric plant in service..................................................... $2,118,417 $2,030,813 Gas plant in service.......................................................... 575,350 553,755 Common plant in service and plant held for future use......................... 45,223 36,678 ----------- ------------ 2,738,990 2,621,246 Less accumulated depreciation and amortization................................ 1,234,629 1,153,377 ----------- ------------ 1,504,361 1,467,869 Construction work in progress................................................. 249,656 123,653 Nuclear fuel, net of accumulated amortization of $16,954 and $19,081.......... 26,940 25,784 ----------- ------------ Net utility plant.......................................................... 1,780,957 1,617,306 ----------- ------------ Other Property and Investments: Other investments (notes 5, 11)............................................... 552,453 479,821 Non-utility property, net of accumulated depreciation of $1,580 and $1,644.... 1,784 3,666 ----------- ------------ Total other property and investments....................................... 554,237 483,487 ----------- ------------ Current Assets: Cash and cash equivalents..................................................... 26,057 107,691 Accounts receivables, net of allowances of $18,025 and $13,279............... 147,787 238,426 Other receivables............................................................. 52,158 64,857 Inventories................................................................... 36,483 36,091 Regulatory assets (note 2).................................................... 10,473 47,604 Short-term investments........................................................ 45,111 - Other current assets.......................................................... 31,428 11,417 ----------- ------------ Total current assets....................................................... 349,497 506,086 ----------- ------------ Deferred charges: Regulatory assets (note 2).................................................... 197,948 228,255 Prepaid pension cost (note 8)................................................. 18,273 18,116 Other deferred charges........................................................ 33,726 36,667 ----------- ------------ Total deferred charges..................................................... 249,947 283,038 ----------- ------------ $2,934,638 $2,889,917 =========== ============
The accompanying notes are an integral part of these financial statements. F-5 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILIITES
As of December 31, -------------------------- 2001 2000 ------------ ------------ (In thousands) Capitalization: (note 3) Common stock equity: Common stock outstanding--39,118 shares, no par value........................ $ 625,632 $ 627,811 Accumulated other comprehensive income, net of tax (note 3).................. (28,996) (27) Retained earnings............................................................ 415,388 296,843 ------------ ------------ Total common stock equity................................................. 1,012,024 924,627 Minority interest.............................................................. 11,652 12,211 Cumulative preferred stock without mandatory redemption requirements........... 12,800 12,800 Long-term debt, less current maturities (note 3)............................... 953,884 953,823 ------------ ------------ Total capitalization........................................................ 1,990,360 1,903,461 ------------ ------------ Current Liabilities: Short-term debt................................................................ 35,000 - Accounts payable............................................................... 120,918 257,991 Accrued interest and taxes..................................................... 72,022 36,889 Other current liabilities...................................................... 101,697 67,758 ------------ ------------ Total current liabilities................................................... 329,637 362,638 ------------ ------------ Deferred Credits: Accumulated deferred income taxes (note 7)..................................... 120,153 166,249 Accumulated deferred investment tax credits (note 7)........................... 44,714 47,853 Regulatory liabilities (note 2)................................................ 52,890 65,552 Regulatory liabilities related to accumulated deferred income tax (note 2)..... 14,163 20,696 Accrued postretirement benefits cost (note 8).................................. 14,929 11,899 Other deferred credits (note 12)............................................... 367,792 311,569 ------------ ------------ Total deferred credits...................................................... 614,641 623,818 ------------ ------------ Commitments and Contingencies (note 11).......................................... - - ------------ ------------ $ 2,934,638 $ 2,889,917 ============ ============
The accompanying notes are an integral part of these financial statements. F-6 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, -------------------------------- 2001 2000 1999 ---------- ---------- ---------- (In thousands) Cash Flows From Operating Activities: Net earnings.......................................................... $150,433 $100,946 $ 83,155 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization..................................... 106,768 103,829 103,891 Gain on cumulative effect of a change in accounting principle .......................................... - - (5,862) Other............................................................. 34,874 33,268 26,170 Changes in certain assets and liabilities: Accounts receivables............................................ 90,639 (90,680) (16,937) Other assets.................................................... 32,481 (32,444) (20,189) Accounts payable................................................ (137,073) 107,346 36,670 Other liabilities............................................... 46,873 18,682 6,147 ---------- ---------- ---------- Net cash flows provided from operating activities......... 324,995 240,947 213,045 ---------- ---------- ---------- Cash Flows From Investing Activities: Utility plant additions............................................... (264,844) (146,878) (95,298) Return of principal PVNGS lessor's notes.............................. 16,674 16,668 16,903 Merger acquisition costs.............................................. (11,567) (6,700) - Short-term and long-term investments.................................. (156,107) (5,307) (3,076) Other investing....................................................... 8,830 (16,715) 25,585 ---------- ---------- ---------- Net cash flows used in investing activities............... (407,014) (158,932) (55,886) ---------- ---------- ---------- Cash Flows From Financing Activities: Borrowings (note 3)................................................... 35,000 - 11,500 Repayments (note 3)................................................... - (32,800) (58,200) Exercise of employee stock options (note 9)........................... (2,179) (1,232) 1,453 Common stock repurchase (note 3)...................................... - (27,867) (18,799) Dividends paid........................................................ (31,876) (32,265) (33,359) Other Financing....................................................... (560) (559) (635) ---------- ---------- ---------- Net cash flows generated (used) by financing activities... 385 (94,723) (98,040) ---------- ---------- ---------- Increase (Decrease) in Cash and Cash Equivalents........................ (81,634) (12,708) 59,119 Beginning of Year....................................................... 107,691 120,399 61,280 ---------- ---------- ---------- End of Year............................................................. $ 26,057 $ 107,691 $ 120,399 ========== ========== ========== Supplemental cash flow disclosures: Interest paid......................................................... $ 62,216 $ 64,045 $ 67,770 ========== ========== ========== Income taxes paid, net of refunds..................................... $ 72,146 $ 50,480 $ 36,575 ========== ========== ========== Acquired pipeline in exchange for transportation services............. $ - $ - $ 3,100 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. F-7 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, -------------------------- 2001 2000 ------------ ------------ (In thousands) Common Stock Equity: (note 3) Common Stock, no par value............................................. $ 625,632 $ 627,811 Accumulated other comprehensive income, net of tax..................... (28,996) (27) Retained earnings...................................................... 415,388 296,843 ------------ ------------ Total common stock equity.......................................... 1,012,024 924,627 ------------ ------------ Minority Interest.......................................................... 11,652 12,211 ------------ ------------ Cumulative Preferred Stock: (note 3) Without mandatory redemption requirements: 1965 Series, 4.58% with a stated value of $100.00 and a current redemption price of $102.00. Outstanding shares at December 31, 2001 were 128,000................................. 12,800 12,800 ------------ ------------ Long-Term Debt: (note 3) Issue and Final Maturity First Mortgage Bonds, Pollution Control Revenue Bonds: 5.7% due 2016..................................................... 65,000 65,000 6.375% due 2022................................................... 46,000 46,000 ------------ ------------ Total First Mortgage Bonds 111,000 111,000 ------------ ------------ Senior Unsecured Notes, Pollution Control Revenue Bonds: 6.30% due 2016.................................................. 77,045 77,045 5.75% due 2022.................................................. 37,300 37,300 5.80% due 2022.................................................. 100,000 100,000 6.375% due 2022.................................................. 90,000 90,000 6.375% due 2023.................................................. 36,000 36,000 6.40% due 2023.................................................. 100,000 100,000 6.30% due 2026.................................................. 23,000 23,000 6.60% due 2029.................................................. 11,500 11,500 ------------ ------------ Total Senior Unsecured Notes, Pollution Control Revenue Bonds..... 474,845 474,845 ------------ ------------ Senior Unsecured Notes: 7.10% due 2005................................................. 268,420 268,420 7.50% due 2018................................................. 100,025 100,025 Other, including unamortized discounts................................ (406) (467) ------------ ------------ Total long-term debt.......................................... 953,884 953,823 ------------ ------------ Total Capitalization....................................................... $1,990,360 $ 1,903,461 ============ ============
The accompanying notes are an integral part of these financial statements. F-8 PNM RESOURCES, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31, ----------------------------------- 2001 2000 1999 ----------- ----------- ----------- (In thousands) Net Earnings............................................................. $150,433 $100,946 $83,155 ----------- ----------- ----------- Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities: Unrealized holding gains arising from the period................... (111) 2,794 4,120 Less reclassification adjustment for gains included in net income.. (345) (5,173) (4,282) Minimum pension liability adjustment................................. (28,858) - 1,387 Mark-to-market adjustment for certain derivative transactions Initial implementation of SFAS 133 designated cash flow hedges..... 6,148 - - Change in fair market value of designated cash flow hedges......... 345 - - Less reclassification adjustment for gains (losses) in cash flow hedges............................................ (6,148) - - ----------- ----------- ----------- Total Other Comprehensive Income......................................... (28,969) (2,379) 1,225 ----------- ----------- ----------- Total Comprehensive Income............................................... $121,464 $ 98,567 $ 84,380 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. F-9 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EARNINGS
Year Ended December 31, -------------------------------------------------- 2001 2000 1999 --------------- --------------- --------------- (In thousands, except per share amounts) Operating Revenues: (note 1) Electric........................................... $1,965,142 $1,289,192 $ 911,977 Gas................................................ 385,418 319,924 236,711 Unregulated businesses............................. 1,538 2,158 8,855 --------------- --------------- --------------- Total operating revenues........................ 2,352,098 1,611,274 1,157,543 --------------- --------------- --------------- Operating Expenses: Cost of energy sold................................ 1,536,566 949,880 531,952 Administrative and general......................... 155,392 147,268 153,709 Energy production costs............................ 152,455 139,894 140,784 Depreciation and amortization...................... 96,936 93,059 92,661 Transmission and distribution costs................ 69,001 60,330 59,264 Taxes, other than income taxes..................... 30,302 34,405 34,084 Income taxes (note 7).............................. 88,769 53,964 25,010 --------------- --------------- --------------- Total operating expenses........................ 2,129,421 1,478,800 1,037,464 --------------- --------------- --------------- Operating income................................ 222,677 132,474 120,079 --------------- --------------- --------------- Other Income and Deductions: Other.............................................. (15,110) 54,296 47,500 Income tax expense (note 7)....................... 7,706 (20,382) (17,298) --------------- --------------- --------------- Net other income and deductions................. (7,404) 33,914 30,202 --------------- --------------- --------------- Income before interest charges.................. 215,273 166,388 150,281 --------------- --------------- --------------- Interest Charges: Interest on long-term debt (note 3)................ 62,716 62,823 65,899 Other interest charges............................. 2,124 2,619 4,768 --------------- --------------- --------------- Net interest charges............................ 64,840 65,442 70,667 --------------- --------------- --------------- Net Earnings from Continuing Operations.............. 150,433 100,946 79,614 Cumulative Effect of a Change in Accounting.......... Principle, Net of Tax............................. - - 3,541 --------------- --------------- --------------- Net Earnings Before Preferred Stock Dividends........ 150,433 100,946 83,155 Preferred Stock Dividend Requirements................ 586 586 586 --------------- --------------- --------------- Net Earnings......................................... $ 149,847 $ 100,360 $ 82,569 =============== =============== ===============
The accompanying notes are an integral part of these financial statements. F-10 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS ASSETS
As of December 31, -------------------------- 2001 2000 ------------ ------------ (In thousands) Utility Plant, at original cost except PVNGS: (notes 10, 11) Electric plant in service..................................................... $2,118,417 $2,030,813 Gas plant in service.......................................................... 575,350 553,755 Common plant in service and plant held for future use......................... 45,223 36,678 ------------ ------------ 2,738,990 2,621,246 Less accumulated depreciation and amortization................................ 1,234,629 1,153,377 ------------ ------------ 1,504,361 1,467,869 Construction work in progress................................................. 249,656 123,653 Nuclear fuel, net of accumulated amortization of $16,954 and $19,081.......... 26,940 25,784 ------------ ------------ Net utility plant.......................................................... 1,780,957 1,617,306 ------------ ------------ Other Property and Investments: Other investments (notes 5, 11)............................................... 446,784 479,821 Non-utility property, net of accumulated depreciation of $1,580 and $1,644.... 1,784 3,666 ------------ ------------ Total other property and investments....................................... 448,568 483,487 ------------ ------------ Current Assets: Cash and cash equivalents..................................................... 14,677 107,691 Accounts receivables, net of allowances of $18,025 and $13,279............... 147,787 238,426 Other receivables............................................................. 52,158 64,857 Inventories................................................................... 36,483 36,091 Regulatory assets (note 2).................................................... 10,473 47,604 Short-term investments........................................................ 45,111 - Other current assets.......................................................... 21,477 11,417 ------------ ------------ Total current assets....................................................... 328,166 506,086 ------------ ------------ Deferred charges: Regulatory assets (note 2).................................................... 187,475 228,255 Prepaid pension cost (note 8)................................................. 18,273 18,116 Other deferred charges........................................................ 44,199 36,667 ------------ ------------ Total deferred charges..................................................... 249,947 283,038 ------------ ------------ $2,807,638 $2,889,917 ============ ============
The accompanying notes are an integral part of these financial statements. F-11 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS CAPITALIZATION AND LIABILIITES
As of December 31, ---------------------------- 2001 2000 ------------- ------------- (In thousands) Capitalization: (note 3) Common Stock Equity: Common stock outstanding 39,118 shares...................................... $195,589 $195,589 Paid-in capital............................................................. 430,043 432,222 Accumulated other comprehensive income, net of tax (note 3)................. (28,996) (27) Retained earnings........................................................... 288,388 296,843 ------------- ------------- Total equity............................................................. 885,024 924,627 Minority interest............................................................. 11,652 12,211 Cumulative preferred stock without mandatory redemption requirements.......... 12,800 12,800 Long-term debt, less current maturities (note 3).............................. 953,884 953,823 ------------- ------------- Total capitalization....................................................... 1,863,360 1,903,461 ------------- ------------- Current Liabilities: Short-term debt............................................................... 35,000 - Accounts payable.............................................................. 120,918 257,991 Accrued interest and taxes.................................................... 72,022 36,889 Other current liabilities..................................................... 101,697 67,758 ------------- ------------- Total current liabilities.................................................. 329,637 362,638 ------------- ------------- Deferred Credits: Accumulated deferred income taxes (note 7).................................... 120,153 166,249 Accumulated deferred investment tax credits (note 7).......................... 44,714 47,853 Regulatory liabilities (note 2)............................................... 52,890 65,552 Regulatory liabilities related to accumulated deferred income tax (note 2).... 14,163 20,696 Accrued postretirement benefits cost (note 8)................................. 14,929 11,899 Other deferred credits (note 12).............................................. 367,792 311,569 ------------- ------------- Total deferred credits..................................................... 614,641 623,818 ------------- ------------- Commitments and Contingencies (note 11)......................................... - - ------------- ------------- $ 2,807,638 $ 2,889,917 ============= =============
The accompanying notes are an integral part of these financial statements. F-12 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, ------------------------------------- 2001 2000 1999 ----------- ----------- ----------- (In thousands) Cash Flows From Operating Activities: Net earnings......................................................... $150,433 $100,946 $ 83,155 Adjustments to reconcile net earnings to net cash flows from operating activities: Depreciation and amortization.................................... 106,768 103,829 103,891 Gain on cumulative effect of a change in Accounting principle ......................................... - - (5,862) Other............................................................ 34,874 33,268 26,170 Changes in certain assets and liabilities: Accounts receivables........................................... 90,639 (90,680) (16,937) Other assets................................................... 42,432 (32,444) (20,189) Accounts payable............................................... (137,073) 107,346 36,670 Other liabilities.............................................. 46,873 18,682 6,147 ----------- ----------- ----------- Net cash flows provided from operating activities........ 334,946 240,947 213,045 ----------- ----------- ----------- Cash Flows From Investing Activities: Utility plant additions.............................................. (264,844) (146,878) (95,298) Return of principal PVNGS lessor's notes............................. 16,674 16,668 16,903 Merger acquisition costs............................................. (11,567) (6,700) - Short-term and long-term investments................................. (50,438) (5,307) - Other investing...................................................... 8,830 (16,715) 22,509 ----------- ----------- ----------- Net cash flows used in investing activities.............. (301,345) (158,932) (55,886) ----------- ----------- ----------- Cash Flows From Financing Activities: Borrowings (note 3).................................................. 35,000 - 11,500 Repayments (note 3).................................................. - (32,800) (58,200) Exercise of employee stock options (note 9).......................... (2,179) (1,232) 1,453 Common stock repurchase (note 3)..................................... - (27,867) (18,799) Dividends paid....................................................... (158,876) (32,265) (33,359) Other Financing...................................................... (560) (559) (635) ----------- ----------- ----------- Net cash flows generated (used) by financing activities.. (126,615) (94,723) (98,040) ----------- ----------- ----------- (Decrease) Increase in Cash and Cash Equivalents....................... (93,014) (12,708) 59,119 Beginning of Year...................................................... 107,691 120,399 61,280 ----------- ----------- ----------- End of Year............................................................ $ 14,677 $ 107,691 $ 120,399 =========== =========== =========== Supplemental cash flow disclosures: Interest paid........................................................ $ 62,216 $ 64,045 $ 67,770 =========== =========== =========== Income taxes paid, net of refunds.................................... $ 72,146 $ 50,480 $ 36,575 =========== =========== =========== Acquired DOE pipeline in exchange for transportation services........ $ - $ - $ 3,100 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. F-13 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION
As of December 31, --------------------------------- 2001 2000 --------------- --------------- (In thousands) Common Stock Equity: (note 3) Common stock outstanding par value $ 5 per share...................... $ 195,589 $ 195,589 Paid-in capital....................................................... 430,043 432,222 Accumulated other comprehensive income, net of tax.................... (28,996) (27) Retained earnings..................................................... 288,388 296,843 --------------- -------------- Total equity...................................................... 885,024 924,627 --------------- -------------- Minority Interest......................................................... 11,652 12,211 --------------- -------------- Cumulative Preferred Stock: (note 3) Without mandatory redemption requirements: 1965 Series, 4.58% with a stated value of $100.00 and a current redemption price of $102.00. Outstanding shares at December 31, 2001 were 128,000................................ 12,800 12,800 --------------- -------------- Long-Term Debt: (note 3) Issue and Final Maturity First Mortgage Bonds, Pollution Control Revenue Bonds: 5.7% due 2016................................................. 65,000 65,000 6.375% due 2022................................................... 46,000 46,000 --------------- -------------- Total First Mortgage Bonds 111,000 111,000 --------------- -------------- Senior Unsecured Notes, Pollution Control Revenue Bonds: 6.30% due 2016................................................. 77,045 77,045 5.75% due 2022................................................. 37,300 37,300 5.80% due 2022................................................. 100,000 100,000 6.375% due 2022.................................................. 90,000 90,000 6.375% due 2023.................................................. 36,000 36,000 6.40% due 2023................................................. 100,000 100,000 6.30% due 2026................................................. 23,000 23,000 6.60% due 2029................................................. 11,500 11,500 --------------- -------------- Total Senior Unsecured Notes, Pollution Control Revenue Bonds.... 474,845 474,845 --------------- -------------- Senior Unsecured Notes: 7.10% due 2005................................................ 268,420 268,420 7.50% due 2018................................................ 100,025 100,025 Other, including unamortized discounts............................... (406) (467) --------------- -------------- Total long-term debt......................................... 953,884 953,823 --------------- -------------- Total Capitalization...................................................... $ 1,863,360 $ 1,903,461 =============== ==============
The accompanying notes are an integral part of these financial statements. F-14 PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year Ended December 31, --------------------------------- 2001 2000 1999 ---------- ---------- --------- (In thousands) Net Earnings.............................................................. $150,433 $100,946 $83,155 ---------- ---------- --------- Other Comprehensive Income, net of tax: Unrealized gain (loss) on securities: Unrealized holding gains arising from the period.................... (111) 2,794 4,120 Less reclassification adjustment for gains included in net income... (345) (5,173) (4,282) Minimum pension liability adjustment.................................. (28,858) - 1,387 Mark-to-market adjustment for certain derivative transactions Initial implementation of SFAS 133 designated cash flow hedges...... 6,148 - - Change in fair market value of designated cash flow hedges.......... 345 - - Less reclassification adjustment for gains (losses) in cash flow hedges............................................. (6,148) - - ---------- ---------- --------- Total Other Comprehensive Income.......................................... (28,969) (2,379) 1,225 ---------- ---------- --------- Total Comprehensive Income................................................ $121,464 $ 98,567 $84,380 ========== ========== =========
The accompanying notes are an integral part of these financial statements. F-15 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 2001, 2000 and 1999 Summary of Significant Accounting Policies Nature of Business PNM Resources, Inc. (the "Company") is a holding company of energy and energy related activities. Its principal subsidiary, Public Service Company of New Mexico ("PNM"), is an integrated public utility primarily engaged in the generation, transmission, distribution and sale and trading of electricity; transmission, distribution and sale of natural gas within the State of New Mexico and the sale and trading of electricity in the Western United States. In addition, the Company provides energy and utility related services under its wholly-owned subsidiary, Avistar, Inc. ("Avistar"). Upon the completion on December 31, 2001, of a one-for-one share exchange between PNM and the Company, the Company became the parent company of PNM. Prior to the share exchange, the Company had existed as a subsidiary of PNM. The new holding company began trading on the New York Stock Exchange under the same PNM symbol beginning on December 31, 2001. Presentation The Notes to the Consolidated Financial Statements of the Company and PNM are presented on a combined basis. The Company as an unconsolidated holding company ("Holding Company") had no material operations for the year ended December 31, 2001. Except for its consolidated investment in PNM, the Holding Company's only assets were cash of $11 million, short-term investments of $10 million and long-term investments of $106 million at December 31, 2001. In addition, the Holding Company had no liabilities at December 31, 2001. Accordingly, the reader of the Notes to the Consolidated Financial Statements should assume that the information presented applies to consolidated results of operations and financial position of both the Company and PNM, except where the context or references clearly indicate otherwise. Discussions regarding specific contractual obligations generally reference the company that is legally obligated. In the case of contractual obligations of PNM, these obligations are consolidated with the Company under Generally Accepted Accounting Principles. Broader operational discussion references the Company. Accounting Principles The Company prepares its financial statements in accordance with the uniform system of accounts prescribed by the Federal Energy Regulatory Commission ("FERC") and the National Association of Regulatory Utility Commissioners, and adopted by the New Mexico Public Regulation Commission ("PRC"), the successor of the New Mexico Public Utility Commission ("NMPUC"), effective January 1, 1999. The Company's accounting policies conform to the provisions of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation ("SFAS 71"). SFAS 71 requires a rate-regulated entity to reflect the effects of regulatory decisions in its financial statements. In accordance with SFAS 71, the Company has deferred certain costs and recorded certain liabilities pursuant to the rate actions of the PRC, NMPUC and FERC. These "regulatory assets" and "regulatory liabilities" are enumerated and discussed in Note 2. F-16 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 To the extent that the Company concludes that the recovery of a regulatory asset is no longer probable due to regulatory treatment, the effects of competition or other factors, the amount would be recorded as a charge to earnings as recovery is no longer probable. The Company has discontinued the application of SFAS 71 as of December 31, 1999, for the generation portion of its business effective with the passage of the Electric Utility Industry Restructuring Act of 1999 ("Restructuring Act") in accordance with Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuation of Application of FASB Statement No. 71 ("SFAS 101"). The Company evaluates its regulatory assets under Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of ("SFAS 121"). In 2000, the Company determined certain stranded costs would not be recovered and recorded a charge to earnings for these amounts recorded as stranded cost assets. The Company believes that it will recover costs associated with its remaining stranded cost assets including asset closure costs through a non-bypassable charge as permitted by the Restructuring Act. See Note 2 for additional discussion. Principles of Consolidation The consolidated financial statements include the accounts of the Company and subsidiaries in which it owns a majority voting interest or meets the criteria of Emerging Issues Task Force 90-15, Impact of Non-Substantive Lessors, Residual Value Guarantees and Other Provisions in Leasing Transactions. All significant intercompany transactions and balances have been eliminated. There were no intercompany transactions between the Company and PNM in 2001, except the dividend described in Note 3. Financial Statement Preparation The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual recorded amounts could differ from those estimated. Utility Plant Utility plant, with the exception of Palo Verde Nuclear Generating Station ("PVNGS") Unit 3, a portion San Juan Generating Station ("SJGS") Unit 4 and the Company's owned interests in PVNGS Units 1 and 2, is stated at original cost, which includes capitalized payroll-related costs such as taxes, pension and other fringe benefits, administrative costs and an allowance for funds used during construction. In 1989, PVNGS Unit 3 and a portion of SJGS Unit 4 were excluded from the jurisdictional rate base. As a result, PNM, wrote-down $17.4 million of its carrying cost related to these assets. In 1993, PNM announced specific actions determined to be necessary in order to accelerate PNM's preparation for the competitive electric energy market. As part of this announcement, PNM stated its intention to attempt to sell PVNGS Unit 3. As a result, PNM wrote-down PVNGS Unit 3 $181.3 million based on the estimated net realizable value of the asset. Since that time, PNM has decided not to sell PVNGS Unit 3. In connection with a rate reduction in 1994, the Company wrote down $131.6 million of its owned interest in Units 1 and 2. Pursuant to a rate F-17 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 stipulation dated October 1993, the Company did not capitalize amounts relating to an allowance for funds used during construction in 2001, 2000 or 1999. Utility plant includes certain electric assets not subject to regulation. It is Company policy to charge repairs and minor replacements of property to maintenance expense and to charge major replacements to utility plant. Gains or losses resulting from retirements or other dispositions of operating property in the normal course of business are credited or charged to the accumulated provision for depreciation. Investments The Company's investments comprise U.S., state, and municipal government obligations and corporate securities. Investments with maturities of less than one year are considered short-term and are carried at fair value. All investments are held in the Company's name and custodied with major financial institutions. The specific identification method is used to determine the cost of securities disposed of, with realized gains and losses reflected in other income and expense. At December 31, 2001, all of the Company's investments were classified as available for sale. Unrealized gains and losses on these investments are included as a separate component of shareholders' equity, net of any related tax effect. Revenue Recognition The Company's Utility Operations record electric and gas operating revenues in the period of delivery, which includes estimated amounts for service rendered but unbilled at the end of each accounting period. Utility Operations gas operating revenues exclude adjustments for differences in gas purchase costs that are above or below levels included in base rates but are recoverable under the Purchased Gas Adjustment Clause ("PGAC") administered by the PRC. The Company recognizes this adjustment when it is permitted to bill under PRC guidelines. The Company's Generation and Trading Operations record operating revenues to the Utility Operations and to third parties in the period of delivery or as services are provided. These electricity sales are recorded as operating revenues while the electricity purchases are recorded as costs of energy sold. These amounts are recorded on a gross basis, because the Company does not act as an agent or broker for these energy trading contracts but takes title and has the risks and rewards of ownership. Certain sales to firm-requirements wholesale customers include a cost of energy adjustment for recoverable fixed costs. The Company recognizes this adjustment when it is permitted to bill under FERC guidelines. Generation and Trading Operations transactions that are net settled, are recorded gross in operating revenues and fuel and purchased power expense. "Net settling" is where the unplanned netting of delivery and acceptance of electric power for convenience of transmission and settlement occurs (referred to as a "bookout"). The Company enters into energy trading contracts to take advantage of market opportunities associated with the purchase and sale of electricity. Unrealized gains and losses resulting from the impact of price movements on the Company's trading contracts are recognized as adjustments to Generation and Trading Operations operating revenues. The market prices used to value these F-18 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 trading transactions reflect management's best estimate considering various factors including closing exchange and over-the-counter quotations, time value and volatility factors underlying the commitments. The cash flow impact of these financial instruments is reflected as cash flows from operating activities in the Consolidated Statement of Cash Flows. Recoverable Fuel Costs The Company's fuel and purchased power costs for its firm-requirements wholesale customers that are above the levels included in base rates are recoverable under a fuel and purchased power cost adjustment approved by the FERC. The costs are deferred until the period in which they are billed or credited to customers. The Company's gas purchase costs are recoverable under a similar Purchased Gas Adjustment Clause administered by the PRC. Depreciation and Amortization Provision for depreciation and amortization of utility plant is made at annual straight-line rates approved by the PRC. The average rates used are as follows: 2001 2000 1999 --------- -------- -------- Electric plant ...................... 3.39% 3.42% 3.38% Gas plant ........................... 3.19% 3.28% 3.37% Common plant ........................ 6.92% 6.75% 7.73% The provision for depreciation of certain equipment is allocated to operating expenses or construction projects based on the use of the equipment. Depreciation of non-utility property is computed on the straight-line method. Amortization of nuclear fuel is computed based on the units of production method. Nuclear Decommissioning The Company accounts for nuclear decommissioning costs on a straight-line basis over the respective license period. Such amounts are based on the future value of expenditures estimated to be required to decommission the plant. For gas, the excess or deficiency is accumulated for refund or surcharge to customers on an annual basis. Future recovery of these costs is subject to approval by the PRC. Amortization of Debt Acquisition Costs Discount, premium and expense related to the issuance of long-term debt are amortized over the lives of the respective issues. In connection with the retirement of long-term debt, such amounts associated with resources subject to PRC regulation are amortized over the lives of the respective issues. Amounts F-19 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 associated with the Company's firm-requirements wholesale customers and its resources excluded from PRC retail rates are recognized immediately as expense or income as they are incurred. Financial Instruments In December 1998, the Emerging Issues Task Force ("EITF") of the Financial Accounting Standards Board ("FASB") reached consensus on EITF Issue No. 98-10 which requires that energy trading contracts should be marked-to-market (measured at fair value determined as of the balance sheet date) with the gains and losses included in earnings. Effective January 1, 1999, the Company adopted EITF Issue No. 98-10. The effect of the initial application of the new standard is reported as a cumulative effect of a change in accounting principle. (See Note 5) The Company implemented Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, ("SFAS 133"), as amended, on January 1, 2001. SFAS 133, as amended, establishes accounting and reporting standards requiring derivative instruments to be recorded in the balance sheet as either an asset or liability measured at their fair value. SFAS 133, as amended, also requires that changes in the derivatives' fair value be recognized currently in earnings unless specific hedge accounting or normal purchase and sale criteria are met. Special accounting for qualifying hedges allows derivative gains and losses to offset related results on the hedged item in the income statement, and requires that a company must formally document, designate, and assess the effectiveness 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. Stock Options The Company accounts for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees". Compensation cost for stock options, if any, is measured as the excess of the quoted market price of the Company's stock at the date of grant over the exercise price of the granted stock option. Restricted stock is recorded as compensation cost over the requisite vesting periods based on the market value on the date of grant. Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation ("SFAS 123"), established accounting and disclosure requirements using a fair-value-based method of accounting for stock-based employee compensation plans. The Company has elected to remain on its current method of accounting as described above, and has adopted the disclosure requirements of SFAS No. 123. F-20 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 Income Taxes The Company accounts for income taxes in accordance with the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("SFAS No. 109"), which uses the asset and liability method for accounting for income taxes. Under SFAS 109, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying value of existing assets and liabilities and their respective tax basis. Current PRC jurisdictional rates include the tax effects of the majority of these differences. SFAS No. 109 requires that rate-regulated enterprises record deferred income taxes for temporary differences accorded flow-through treatment at the direction of a regulatory commission. The resulting deferred tax assets and liabilities are recorded at the expected cash flow to be reflected in future rates. Since the PRC has consistently permitted the recovery of previously flowed-through tax effects, the Company has established regulatory liabilities and assets offsetting such deferred tax assets and liabilities. Items accorded flow-through treatment under PRC orders, deferred income taxes and the future ratemaking effects of such taxes, as well as corresponding regulatory assets and liabilities, are recorded in the financial statements. Asset Impairment The Company regularly evaluates the carrying value of its regulatory and tangible long-lived assets in relation to their future undiscounted cash flows to assess recoverability in accordance with SFAS 121. Impairment testing of power generation assets is performed periodically in response to changes in market conditions resulting from industry deregulation. Power generation assets used to supply jurisdictional and wholesale markets are evaluated on a group basis using future undiscounted cash flows based on current open market price conditions. The Company also has generation assets that are used for the sole purpose of reliability. These assets are tested as an individual group. Power generation assets held under operating leases are not currently evaluated for impairment as currently prescribed by GAAP (see Note 4). Change in Presentation Certain prior year amounts have been reclassified to conform to the 2001 financial statement presentation. (1) Segment Information As it currently operates, the Company's principal business segments are Utility Operations, which include Electric Services ("Electric") and Gas Services ("Gas"), and Generation and Trading Operations ("Generation and Trading"). Electric consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment due to its immateriality and is combined with the distribution business line for disclosure purposes. F-21 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 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. Approximately 378,000, 369,000 and 361,000 retail electric customers were served by the Company at December 31, 2001, 2000 and 1999, respectively. The Company owns or leases 2,890 circuit miles of transmission lines, interconnected with other utilities in New Mexico and south and east into Texas, west into Arizona, and north into Colorado and Utah. Electric exclusively acquires its electricity sold to retail customers from the Company's Generation and Trading Operations. Intersegment purchases from the Generation and Trading Operations are priced using internally developed transfer pricing and are not based on market rates. Customer rates for electric service are set by the PRC based on the recovery of the cost of power production and a rate of return that includes certain generation assets that are part of Generation and Trading Operations, among other things. Gas The Company's gas operations distribute natural gas to most of the major communities in New Mexico, including Albuquerque and Santa Fe, serving approximately 443,000, 435,000 and 426,000 customers as of December 31, 2001, 2000 and 1999, respectively. The Company's customer base includes both sales-service customers and transportation-service customers. In 2000 and the first quarter of 2001, the Company's Generation and Trading Operations procured its gas fuel supply from Gas. In the second quarter of 2001, the Company's Generation and Trading Operations began procuring its gas supply independent of Gas and contracting with Gas for transportation services only. GENERATION AND TRADING OPERATIONS The Company's Generation and Trading Operations serve four principal markets. These include sales to the Company's Utility Operations to cover jurisdictional electric demand, sales to firm-requirements wholesale customers, other contracted sales to third parties for a specified amount of capacity (measured in megawatts-MW) or energy (measured in megawatt hours-MWh) over a given period of time and energy sales made on an hourly basis at fluctuating, spot-market rates. In addition to generation capacity, the Company purchases power in the open market. As of December 31, 2001, the total net generation capacity of facilities owned or leased by the Company was 1,653 MW, including a 132 MW power purchase contract accounted for as an operating lease. F-22 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 UNREGULATED AND OTHER The Company's wholly-owned subsidiary, Avistar, was formed in August 1999 as a New Mexico corporation and is currently engaged in certain unregulated and non-utility businesses. Unregulated also, includes immaterial corporate activities and eliminations. The immaterial corporate activities were assumed by the Company on December 31, 2001. RISKS AND UNCERTAINTIES The Company's future results may be affected by changes in regional economic conditions; the outcome of labor negotiations with unionized employees; fluctuations in fuel, purchased power and gas prices; the actions of utility regulatory commissions; changes in law; 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. The Company's future results will be impacted by its ability to recover its stranded costs, incurred previously in providing power generation to electric service customers, the market price of electricity and natural gas costs and the costs of transition to an unregulated status. In addition, as a result of deregulation, the Company may face competition from companies with greater financial and other resources. Summarized financial information by business segment for 2001, 2000 and 1999 is as follows:
Utility ------------------------------ Unregulated Electric Gas Total Generation and Other Consolidated -------- --- ----- ---------- ----------- ------------ (In thousands) Twelve Months Ended: - -------------------- 2001: Operating revenues: External customers.......... 559,226 385,418 944,644 1,405,916 1,538 2,352,098 Intersegment revenues....... 707 - 707 341,608 (342,315) - Depreciation and amortization.. 32,666 21,465 54,131 42,766 39 96,936 Interest income................ 1,626 935 2,561 39,302 6,157 48,020 Net interest charges........... 19,868 11,807 31,675 28,282 4,883 64,840 Income tax expense (benefit) From continuing operations... 26,547 5,710 32,257 90,097 (41,291) 81,063 Operating income (loss)........ 61,471 20,897 82,368 154,370 (14,061) 222,677 Segment net income (loss)...... 40,507 8,917 49,424 137,485 (36,476) 150,433 Total assets................... 770,798 469,410 1,240,208 1,430,917 263,513 2,934,638 Gross property additions....... 74,316 48,978 123,294 126,605 14,994 264,893
F-23 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999
Summarized financial information by business segment for 2001, 2000 and 1999 is as follows: Utility ---------------------------- Unregulated Electric Gas Total Generation and Other Consolidated -------- --- ----- ---------- ----------- ------------ (In thousands) Twelve Months Ended: - -------------------- 2000: Operating revenues: External customers........... 538,758 319,924 858,682 750,434 2,158 1,611,274 Intersegment revenues........ 707 - 707 324,744 (325,451) - Depreciation and amortization... 31,480 19,994 51,474 41,558 27 93,059 Interest income................. 1,158 517 1,675 39,439 7,581 48,695 Net interest charges............ 17,771 11,089 28,860 36,064 518 65,442 Income tax expense (benefit) From continuing operations.... 30,346 9,632 39,978 45,304 (10,936) 74,346 Operating income (loss)......... 60,583 22,042 82,625 81,525 (31,676) 132,474 Segment net income (loss)....... 43,466 14,327 57,793 75,261 (32,108) 100,946 Total assets.................... 689,489 521,636 1,211,125 1,424,586 254,206 2,889,917 Gross property additions........ 51,815 40,418 92,233 53,025 1,620 146,878
Utility ----------------------------- Unregulated Electric Gas Total Generation and Other Consolidated -------- --- ----- ---------- ----------- ------------ (In thousands) Twelve Months Ended: - -------------------- 1999: Operating revenues: External customers............. 540,868 236,711 777,579 371,109 8,855 1,157,543 Intersegment revenues.......... 707 - 707 318,872 (319,579) - Depreciation and amortization..... 30,183 19,210 49,393 41,183 2,085 92,661 Interest income................... 76 1,066 1,142 39,439 7,581 48,162 Net interest charges.............. 19,822 13,585 33,407 36,561 699 70,667 Income tax expense (benefit) From continuing operations...... 24,174 2,299 26,473 25,086 (9,250) 42,309 Operating income (loss)........... 58,331 16,102 74,433 57,999 (12,353) 120,079 Cumulative effect of a change in Accounting Principle, net of tax - - - 3,541 - 3,541 Segment net income (loss)......... 38,061 2,780 40,841 56,506 (14,192) 83,155 Total assets...................... 715,620 449,790 1,165,410 1,464,423 93,435 2,723,268 Gross property additions.......... 42,253 27,150 69,403 23,899 2,334 95,636
F-24 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 (2) Regulatory Assets and Liabilities The Company is subject to the provisions of SFAS 71, with respect to operations regulated by the PRC. Regulatory assets represent probable future revenue to the Company associated with certain costs, which will be recovered from customers through the ratemaking process. Regulatory liabilities represent probable future reductions in revenues associated with amounts that are to be credited to customers through the ratemaking process. Regulatory assets and liabilities reflected in the Consolidated Balance Sheets as of December 31, relate to the following: 2001 2000 ---------- ------------ (In thousands) Assets: Current: PGAC ........................................ $ 9,065 $ 46,390 Gas Take-or-Pay Costs ....................... 1,408 1,214 ----------- ------------ Subtotal ................................. 10,473 47,604 ----------- ------------ Deferred: Deferred Income Taxes........................ 33,632 33,848 Loss on Reacquired Debt...................... 6,798 7,687 Gas Imputed Revenues......................... 2,310 2,117 Deferred Customer Expense on Gas Assets Sale. - 7,984 Gas Retirees' Health Care Costs.............. - 1,724 Proposed Transmission Line Costs............. 2,222 2,377 Other 1,459 1,888 ----------- ------------ Subtotal.................................. 46,421 57,625 ----------- ------------ Stranded and Transition Assets.................... 151,527 170,630 ----------- ------------ Total Assets.............................. 208,421 275,859 ----------- ------------ Liabilities: Deferred: Deferred Income Taxes........................ (41,915) (43,834) Gas Regulatory Reserve....................... (565) (980) Customer Gain on Gas Assets Sale............. - (7,226) Line Acquisition............................. (1,954) (2,490) Gain on Reacquired Debt...................... (1,640) (1,791) Other........................................ (332) (568) ----------- ------------ Subtotal..................................... (46,406) (56,889) ----------- ------------ Stranded and Transition Liabilities............... (20,647) (29,359) ----------- ------------ Total Liabilities............................ (67,053) (86,248) ----------- ------------ Net Regulatory Assets ....................... $ 141,368 $ 189,611 =========== ============ Substantially all of the Company's regulatory assets and regulatory liabilities are reflected in rates charged to customers or have been addressed in a regulatory proceeding. The Company does not receive or pay a material rate of return on these regulatory assets and regulatory liabilities. F-25 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 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 or determined to be recoverable in rates, in excess of the expected competitive market price 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 also allows for the recovery of nuclear decommissioning costs by means of a separate wires charge over the life of the underlying generation assets. Approximately $142 million of costs associated with the unregulated businesses under the Restructuring Act were established as regulatory assets. Because of the Company's belief that recovery through rates is probable as established by law, these assets continue to be classified as regulatory assets, although the Company's Generation and Trading Operations has discontinued SFAS 71 and adopted SFAS 101. In 2001, the Company recognized the write-off of $13.0 million 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 its holding company filing in May 2001, management determined that it would not seek recovery of a portion of its previously established stranded cost asset that was not a component of retail ratemaking. The remaining portion of costs associated with coal mine decommissioning that are attributed to local jurisdictional customers will be sought in future rate cases. The amendments to the Restructuring Act provide the opportunity for amortization of coal mine decommissioning costs currently estimated at approximately $100 million. The Company intends to seek recovery of these costs in its next rate case filing and believes that the costs are fully recoverable. The Company believes that any remaining portion of the regulatory assets will be fully recovered in future rates, including through a non-bypassable wires charge. Pursuant to the Restructuring Act, utilities will also be allowed to recover in full any prudent and reasonable costs incurred in implementing full open access ("transition costs"). The transition costs are presently scheduled to be recovered beginning 2007 through 2012 by means of a separate wires charge. The Company intends to seek recovery of incurred transition costs in any future rate proceeding held before open access begins. Transition costs include professional fees, financing costs including underwriting fees, costs relating to the transfer of assets, the cost of management information system changes including billing system changes and public and customer communications costs. F-26 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 On December 31, 2001, the Company implemented a holding company structure without separation of supply service and energy-related service assets from distribution and transmission service assets as permitted under the amended Restructuring Act. The Company is unable to predict the form its further restructuring will take under delayed implementation of customer choice. Accordingly, it cannot estimate the total expected amount of transition costs. Recoverable transition costs will be capitalized and amortized over the recovery period to match related revenues. Costs not recoverable will be expensed when incurred unless otherwise capitalizable under the accounting rules. Regulatory assets and liabilities reflected in the Consolidated Balance Sheets as of December 31, related to stranded or transition costs are as follows: 2001 2000 ------------ ----------- (In thousands) Assets: Transition Costs................................. $ 13,208 $ 19,069 Mine Reclamation Costs........................... 100,877 113,856 Deferred Income Taxes............................ 35,775 35,726 Loss on Reacquired Debt.......................... 1,667 1,979 ------------ ----------- Subtotal.................................... 151,527 170,630 ------------ ----------- Liabilities: Deferred Income Taxes............................ (14,163) (20,696) PVNGS Prudence Audit............................. (5,058) (5,434) Settlement Due Customers......................... (1,408) (3,205) Gain on Reacquired Debt.......................... (18) (24) ------------ ----------- Subtotal.................................... (20,647) (29,359) ------------ ----------- Net Stranded Cost and Transition Cost....... $ 130,880 $ 141,271 ============ =========== Based on a current evaluation of the various factors and conditions that are expected to impact future cost recovery, the Company believes that its net regulatory assets are probable of future recovery. (Intentionally Left Blank) F-27 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 (3) Capitalization Changes in common stock, additional paid-in capital and retained earnings are as follows:
Common Stock ----------------------------- Additional Number Aggregate Paid-In Retained Of Shares Par Value Capital Earnings -------------- ------------- ------------- ------------- (Dollars in thousands) Balance at December 31, 1999................ 40,703,383 $203,517 $453,393 $227,829 Stock repurchases........................... (1,585,584) (7,928) (19,939) - Tax benefit from exercise of stock options.. - - (1,232) - Net earnings................................ - - - 100,946 Dividends: Cumulative preferred stock............... - - - (586) Common Stock............................. - - - (31,346) ------------- ------------- ------------- ------------- Balance at December 31, 2000................ 39,117,799 195,589 432,222 296,843 Stock repurchase............................ - - - - Exercise of stock options................... - - (2,179) - Net earnings................................ - - - 150,433 Dividends: Cumulative preferred stock............... - - - (586) Common Stock............................. - - - (31,302) ------------- ------------- ------------- ------------- Balance at December 31, 2001................ 39,117,799 $195,589 $430,043 $415,388 ============= ============= ============= =============
Common Stock The number of authorized shares of common stock of the Company is 120 million shares with no par value. The declaration of common dividends is dependent upon a number of factors including the ability of the Company's subsidiaries to pay dividends. Currently, PNM is the Company's primary source of dividends. As part of the order approving the formation of the holding company, the PRC placed certain restrictions on the ability of PNM to pay dividends to its parent. The PRC order imposed the following conditions regarding dividends paid by PNM to the holding company: PNM can not pay dividends which cause its debt rating to go below investment grade; and PNM can not pay dividends in any year, as determined on a rolling four quarter basis, in excess of net earnings without prior PRC approval. Additionally, PNM has various financial covenants which limit the transfer of assets, through dividends or other means. In addition, the ability of the Company to declare dividends is dependent upon the extent to which cash flows will support dividends, the availability of retained earnings, the financial circumstances and performance, the PRC's decisions in various regulatory cases currently pending and which may be docketed in the future, the effect of deregulating generation markets and market F-28 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 economic conditions generally. The ability to recover stranded costs in deregulation (as amended), conditions imposed on holding company formation, future growth plans and the related capital requirements and standard business considerations may also affect the Company's ability to pay dividends. Consistent with the PRC's holding company order, PNM paid dividends of $127.0 million to the Company on December 31, 2001. On March 4, 2002, the PNM Board of Directors declared an additional dividend of approximately $5.5 million, which was paid March 19, 2002. On February 19, 2002, the Company's Board of Directors approved a 10 percent increase in the common stock dividend. The increase raises the quarterly dividend to $0.22 per share, for an indicated annual dividend of $0.88 per share. The Company's Board of Directors approved a policy for future dividend increases in the range of 8 to 10 percent annually, targeting a payout of between 50 to 60 percent of regulated earnings. The Company believes that this target is consistent with the Company's expectation of future operating cash flows and the cash needs of its planned increase in generating capacity. In March 1999, PNM's Board of Directors approved a plan to repurchase up to 1,587,000 shares of its outstanding common stock with maximum purchase price of $19.00 per share. In December 1999, PNM Board of Directors authorized PNM to repurchase up to an additional $20.0 million of its common stock. As of December 31, 1999, PNM repurchased 1,070,700 shares of its previously outstanding common stock at a cost of $18.8 million. From January 2000 through March 2000, PNM repurchased an additional 963,284 shares of its outstanding common stock at a cost of $18.8 million. 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 year ended December 31, 2001. In September of 2001, the Board authorized further repurchases of stock. However, the Company has not exercised this authority. Cumulative Preferred Stock No Holding Company preferred stock is outstanding. The Company's restated articles of incorporation authorize 10 million shares of preferred stock, which may be issued without restriction. The number of authorized shares of PNM cumulative preferred stock is 10 million shares. PNM has 128,000 shares, 1965 Series, 4.58%, stated value of $100 per share, of cumulative preferred stock outstanding. The 1965 Series does not have a mandatory redemption requirement but may be redeemable at 102% of the par value with accrued dividends. The holders of the 1965 Series are entitled to payment before holders of common stock in the event of any liquidation or dissolution or distribution of assets of PNM. In addition, the 1965 Series is not entitled to a sinking fund and cannot be converted into any other class of stock of PNM. Long-Term Debt PNM has $268,420,000 of long-term debt that matures in August 2005. All other long-term debt matures in 2016 or later. On March 11, 1998, PNM modified its 1947 Indenture of Mortgage and Deed of Trust; no future bonds can be issued under the mortgage. While first mortgage bonds continue to serve as collateral for PCBs in the outstanding principal amount of $111 million, the lien of the mortgage covers only PNM's ownership interest in PVNGS. Senior unsecured notes ("SUNs"), which were issued under a senior unsecured note indenture, serve as collateral for PCBs in the outstanding F-29 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 principal amount of $463.3 million. With the exception of the $111 million of PCBs secured by first mortgage bonds, the SUNs are and will be the senior debt of PNM. In August 1998, PNM issued and sold $435 million of SUNs in two series, the 7.10% Series A due August 1, 2005, in the principal amount of $300 million, and the 7.50% Series B due August 1, 2018, in the principal amount of $135 million. These SUNs were issued under an indenture similar to the indenture under which the SUNs were issued and it is expected that future long-term debt financings will be similarly issued. In 1999, PNM retired $31.6 million of its 7.10% senior unsecured notes through open market purchases, utilizing the funds from operations and the funds from temporary investments leaving an outstanding principal balance of $268.4 million. In January 2000, PNM retired $35.0 million of its 7.5% senior unsecured notes through open market purchases utilizing funds from operations and the funds from temporary investments leaving an outstanding principal balance of $100.0 million. The gains recognized on these purchases were immaterial. On October 28, 1999, tax-exempt pollution control revenue bonds of $11.5 million with an interest rate of 6.60% were issued by PNM to provide partial reimbursement for expenditures associated with its share of a recently completed upgrade of the emission control system at SJGS. Revolving Credit Facility and Other Credit Facilities At December 31, 2001, PNM had a $150 million unsecured revolving credit facility (the "Facility") with an expiration date of March 11, 2003. PNM must pay commitment fees of 0.1875% per year on the total amount of the Facility. PNM also had $20 million in local lines of credit. In addition, the Holding Company has a $20 million reciprocal borrowing agreement with PNM and $25 million in local lines of credit. There were $35.0 million in outstanding borrowings under the Facility, bearing interest at 2.3875%, under the Facility as of December 31, 2001. On January 31, 2002, this amount was refunded at an interest rate of 2.325%. Subsequent to December 31, 2001, an additional $40.0 million was borrowed at an interest rate of 2.20%, which was subsequently refunded at an interest rate of 2.3875% as of March 1, 2002. PNM was in compliance with all covenants under the Facility. (4) Lease Commitments PNM leases interests in Units 1 and 2 of PVNGS, certain transmission facilities, office buildings and other equipment under operating leases. The lease expense for PVNGS is $66.3 million per year over base lease terms expiring in 2015 and 2016. Covenants in PNM's PVNGS Units 1 and 2 lease agreements limit PNM's ability, without consent of the owner participants in the lease transactions, (i) to enter into any merger or consolidation, or (ii) except in connection with normal dividend policy, to convey, transfer, lease or dividend more than 5% of its assets in any single transaction or series of related transactions. F-30 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 In 1998, PNM established PVNGS Capital Trust ("Capital Trust"), for the purpose of acquiring all the debt underlying the PVNGS leases. PNM consolidates Capital Trust in its consolidated financial statements. The purchase was funded with the proceeds from the issuance of $435 million of SUNS (see Note 3), which were loaned to Capital Trust. Capital Trust then acquired and holds the debt component of the PVNGS leases. For legal and regulatory reasons, the PVNGS lease payment continues to be recorded and paid gross with the debt component of the payment returned to PNM via Capital Trust. As a result, the net cash outflows for the PVNGS lease payment were $12.4 million in 2001. The summary of PNM's future minimum operating lease payments below, reflects the net cash outflow related to the PVNGS leases. PNM's other significant operating lease obligations include a transmission line with annual lease payments of $7.3 million and a power purchase agreement for the entire output of a gas-fired generating plant in Albuquerque, New Mexico with imputed annual lease payments of $6.0 million. Future minimum operating lease payments (in thousands) at December 31, 2001 are: 2002........................................ $ 32,095 2003........................................ 33,049 2004........................................ 33,113 2005........................................ 34,769 2006........................................ 35,587 Later years................................. 364,341 ----------- Total minimum lease payments ............ $ 532,954 =========== Operating lease expense, inclusive of the net PVNGS lease payment, was approximately $32.7 million in 2001, $28.5 million in 2000 and $23.7 million in 1999. Aggregate minimum payments to be received in future periods under non-cancelable subleases are approximately $5.3 million. (Intentionally left blank) F-31 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 (5) Financial Instruments The estimated fair value of the Company's financial instruments (including current maturities) at December 31, is as follows:
2001 2000 ---- ---- Carrying Fair Carrying Fair Amount Value Amount Value ------------------------- ------------------------- (In thousands) Short-term and long-term investment securities..................... $ 150,781(1) $ 150,781(1) $ - $ - Long-Term Debt .............................. $ 953,884 $ 973,975 $ 953,823 $ 930,359 Investment in PVNGS Lessors' Notes........... $ 387,347 $ 453,028 $ 405,960 $ 440,079 Decommissioning Trust........................ $ 57,284 $ 57,284 $ 54,977 $ 54,977 Fossil-Fueled Plant Decommissioning Trust.... $ - $ - $ 4,760 $ 4,760 Rabbi Trust.................................. $ 10,848 $ 10,848 $ 14,281 $ 14,281
(1) $116 million of investments are held by the Holding Company. Fair value is based on market quotes provided by the Company's investment bankers and trust advisors. The carrying amounts reflected on the consolidated balance sheets approximate fair value for cash, temporary investments, and receivables and payables due to the short period of maturity. The Company uses derivative financial instruments to manage risk as it relates to changes in natural gas and electric prices, interest rates of future debt issuances and adverse market changes for investments held by the Company's various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of favorable price movements and market timing activities in the wholesale power markets. The Company is exposed to credit risk in the event of non-performance or non-payment by counterparties of its financial derivative instruments. The Company uses a credit management process to assess and monitor the financial conditions of counterparties. The Company's credit risk with its largest counterparty as of December 31, 2001 and 2000 was $7.5 million and $16.7 million, respectively. F-32 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 Natural Gas Contracts Utility Operations Pursuant to a 1997 order issued by the NMPUC, predecessor to the PRC, the Company has previously entered into swaps to hedge certain portions of natural gas supply contracts in order to protect the Company's natural gas customers from the risk of adverse price fluctuations in the natural gas market. The financial impact of all hedge gains and losses from swaps is recoverable through the Company's purchased gas adjustment clause as deemed prudently incurred by the PRC. As a result, earnings are not affected by gains or losses generated by these instruments. The Company purchased gas options, a type of hedge, to protect its natural gas customers from price risk during the 2001-2002 heating season. The Company expended $9.4 million to purchase options that limit the maximum amount the Company would pay for gas during the winter heating season. The Company recovered its actual hedging expenditures as a component of the PGAC during the months of October 2001 through February 2002 in equal allotments of $1.88 million. As winter 2001-2002 gas prices were substantially lower than the previous year, the hedges placed for this winter expired unexercised. Generation and Trading Commencing in 2000, the Company's Generation and Trading Operations conducted a hedging program to reduce its exposure to fluctuations in prices for natural gas used as a fuel source for some of its generation. The Generation and Trading Operations purchased futures contracts for a portion of its anticipated natural gas needs in the second, third and fourth quarters of 2001. The futures contracts capped the Company's natural gas purchase prices at $5.08 to $6.40 per MMBTU and had a notional amount of $33.6 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 accounted 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 were reclassified and recognized in earnings as an adjustment to the Company's cost of fuel when the hedged transaction affected earnings. The fuel hedge program ended in December 2001. Electricity Trading Contracts For the year ended December 31, 2001, the Company's wholesale electric trading operations settled trading contracts for the sale of electricity that generated $77.9 million of electric revenues by delivering 448,000 MWh. The Company purchased $76.7 million or 428,000 MWh of electricity to support these contractual sales and other open market sales opportunities. For the year ended December 31, 2000, the Company's wholesale electric trading operations settled trading contracts for the sale of electricity that generated $88.9 million of electric revenues by delivering 2.1 million KWh. The Company purchased $78.6 million or 1.9 million KWh of electricity to support these contractual sales and other open market sales opportunities. F-33 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 As of December 31, 2001, the Company had open trading contract positions to buy $66.9 million and to sell $25.7 million of electricity. At December 31, 2001, the Company had a gross mark-to-market gain (asset position) on these trading contracts of $10.9 million and gross mark-to-market loss (liability position) of $41.4 million, with net mark-to-market loss (liability position) of $30.5 million. The change in 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 December 31, 2001, the Company had open forward positions classified as normal sales of electricity of $48.9 million and normal purchases of electricity of $8.1 million. The Company's Generation and Trading Operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Company's aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases. Forward Starting Interest Rate Swaps PNM currently has $182.0 million of tax-exempt bonds outstanding that are callable at a premium in December 2002 and August 2003. PNM intends to refinance these bonds assuming the interest rate of the refinancing does not exceed the current interest rate and has hedged the entire planned refinancing. In order to take advantage of current low interest rates, PNM entered into two forward starting interest rate swaps in November and December 2001 and three additional contracts subsequent to December 31, 2001. PNM designated these swaps as cash flow hedges. The hedged risks associated with these instruments are the changes in cash flows related to general moves in interest rates expected for the refinancing. The swaps effectively cap the interest on the refinancing to 4.9% plus an adjustment for PNM's and the industry's credit rating. PNM's assessment of hedge effectiveness is based on changes in the interest rates and PNM's credit spread. SFAS 133, as amended, provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period or periods during which the hedged forecasted transactions affects earnings. Any hedge ineffectiveness is required to be presented in current earnings. There was no material hedge ineffectiveness in the year ended December 31, 2001. F-34 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 A forward starting swap does not require any upfront premium and captures changes in the corporate credit component of an investment grade company's interest rate as well as the underlying Treasury benchmark. The five forward interest rate starting swaps have termination dates and notional amounts as follows: one with a termination date of September 17, 2002 for a notional amount of $46.0 million and four with a termination date of May 15, 2003 for a combined notional amount of $136.0 million. There were no fees on the transaction, as they are imbedded in the rates, and the transaction is cash settled on the mandatory unwind date (strike date), corresponding to the refinancing date of the underlying debt. The settlement will be capitalized as a cost of issuance and amortized over the life of the debt as a yield adjustment. Hedge of Trust Assets In February 2001, PNM 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. PNM recognized a realized gain of $0.5 million (pretax) as a result. Previously, changes in fair market value were recorded in PNM's results of operations. (Intentionally left blank) F-35 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 (6) Earnings Per Share In accordance with SFAS No. 128, Earnings per Share, dual presentation of basic and diluted earnings per share has been presented in the Consolidated Statements of Earnings. The following reconciliation illustrates the impact on the share amounts of potential common shares and the earnings per share amounts:
2001 2000 1999 ------------- ------------- ------------- (In thousands, except per share amounts) Basic: Net Earnings from Continuing Operations..................... $ 150,433 $ 100,946 $ 79,614 Cumulative Effect of a Change in Accounting Principle, net of tax.................................... - - 3,541 ------------- ------------- ------------- Net Earnings................................................ 150,433 100,946 83,155 Preferred Stock Dividend Requirements....................... 586 586 586 ------------- ------------- ------------- Net Earnings Applicable to Common Stock..................... $ 149,847 $ 100,360 $ 82,569 ============= ============= ============= Average Number of Common Shares Outstanding................. 39,118 39,487 41,038 ============= ============= ============= Net Earnings per Share of Common Stock: Earnings from continuing operations....................... $ 3.83 $ 2.54 $ 1.93 Cumulative effect of a change in accounting principle..... - - - ------------- ------------- ------------- Net Earnings per Share of Common Stock (Basic).............. $ 3.83 $ 2.54 $ 2.01 ============= ============= ============= Diluted: Net Earnings from Continuing Operations..................... $ 150,433 $ 100,946 $ 79,614 Cumulative Effect of a Change in Accounting Principle, net of tax.................................... - - 3,541 ------------- ------------- ------------- Net Earnings................................................ 150,433 100,946 83,155 Preferred Stock Dividend Requirements....................... 586 586 586 ------------- ------------- ------------- Net Earnings Applicable to Common Stock..................... $ 149,847 $ 100,360 $ 82,569 ============= ============= ============= Average Number of Common Shares Outstanding................. 39,118 39,487 41,038 Diluted Effect of Common Stock Equivalents (a).............. 613 223 65 ------------- ------------- ------------- Average common and common equivalent shares Outstanding............................................... 39,731 39,710 41,103 ============= ============= ============= Net Earnings per Share of Common Stock: Earnings from continuing operations....................... $ 3.77 $ 2.53 $ 1.93 Cumulative effect of a change in accounting principle..... - - - ------------- ------------- ------------- Net Earnings per Share of Common Stock (Diluted).............. $ 3.77 $ 2.53 $ 2.01 ============= ============= =============
(a) Excludes the effect of average anti-dilutive common stock equivalents related to out of-the-money options of 105,336 and 66,143 for the years ended 2000 and 1999, respectively. There were no anti-dilutive common stock equivalents in 2001. F-36 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 (7) Income Taxes Income taxes before discontinued operations and cumulative effect of a change in accounting principle consist of the following components:
2001 2000 1999 ----------- ------------ ----------- (In thousands) Current Federal income tax .............................. $ 97,661 $ 41,666 $ 23,511 Current state income tax ................................ 21,220 13,726 8,502 Deferred Federal income tax ............................. (28,967) 19,729 13,494 Deferred state income tax ............................... (5,712) 2,368 210 Amortization of accumulated investment tax credits ...... (3,139) (3,143) (3,409) ----------- ------------ ----------- Total income taxes ................................... $ 81,063 $ 74,346 $ 42,308 Charged to operating expenses ........................... $ 88,769 $ 53,964 $ 25,010 Charged to other income and deductions .................. (7,706) 20,382 17,298 ----------- ------------ ----------- Total income taxes.................................... $ 81,063 $ 74,346 $ 42,308 =========== ============ ===========
The Company's provision for income taxes before discontinued operations and cumulative effect of a change in accounting principle differed from the Federal income tax computed at the statutory rate for each of the years shown. The differences are attributable to the following factors:
2001 2000 1999 ----------- ----------- ----------- (In thousands) Federal income tax at statutory rates ................ $ 81,024 $ 61,352 $ 42,673 Investment tax credits ............................... (3,139) (3,143) (3,409) Depreciation of flow-through items ................... 2,249 2,250 605 Gains on the sale and leaseback of PVNGS Units 1 and 2 ..................................... (527) (527) (527) Equity income from passive investments................ (1,180) - (1,301) Annual reversal of deferred income taxes accrued at prior tax rates................................. (1,963) (2,477) (2,320) Valuation reserve for regulatory recoverability....... (6,552) 6,552 - State income tax ..................................... 10,706 8,343 5,541 Other ................................................ 445 1,996 1,046 ----------- ----------- ----------- Total income taxes ................................ $ 81,063 $ 74,346 $ 42,308 =========== =========== =========== Effective tax rate 35.02% 42.41% 34.70% =========== =========== ===========
F-37 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 The components of the net accumulated deferred income tax liability were: 2001 2000 ---------- ---------- (In thousands) Deferred Tax Assets: Nuclear decommissioning costs...................... $28,138 $23,892 Regulatory liabilities related to income taxes .... 40,594 41,695 Other ............................................. 78,973 69,469 ---------- ---------- Total deferred tax assets ...................... 147,705 135,056 ---------- ---------- Deferred Tax Liabilities: Depreciation ...................................... 189,157 184,127 Investment tax credit ............................. 44,714 47,853 Fuel costs ........................................ 5,515 24,808 Regulatory assets related to income taxes.......... 68,086 67,435 Other ............................................. 19,263 45,631 ---------- ---------- Total deferred tax liabilities ................. 326,735 369,854 ---------- ---------- Accumulated deferred income taxes, net ............... $179,030 $234,798 ========== ========== The following table reconciles the change in the net accumulated deferred income tax liability to the deferred income tax expense included in the consolidated statement of earnings for the period:
Net change in deferred income tax liability per above table..................... $(55,768) Change in tax effects of income tax related regulatory assets and liabilities... (1,752) Tax effect of mark-to-market on investments available for sale.................. 790 Tax effect of excess pension liability.......................................... 18,912 ----------- Deferred income tax expense from continuing operations for the period........ $(37,818) ===========
The Company has no net operating loss carryforwards as of December 31, 2001. The Company defers investment tax credits related to rate regulated assets and amortizes them over the estimated useful lives of those assets. The Company anticipates that this practice will continue when the generation assets are no longer rate regulated upon full implementation of the Restructuring Act. (8) Pension and Other Postretirement Benefits Pension Plan The Company and its subsidiaries have a pension plan covering substantially all of their union and non-union employees, including officers. The plan is non-contributory and provides for benefits to be paid to eligible employees at retirement based primarily upon years of service with the Company and the average of their highest annual base salary for three consecutive years. F-38 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 The Company's policy is to fund actuarially-determined contributions. Contributions to the plan reflect benefits attributed to employees' years of service to date and also for services expected to be provided in the future. Plan assets primarily consist of common stock, fixed income securities, cash equivalents and real estate. In December 1996, the Board of Directors approved changes to the Company's non-contributory defined benefit plan ("Retirement Plan") and the implementation of a 401(k) defined contribution plan effective January 1, 1998. Salaries used in Retirement Plan benefit calculations were frozen as of December 31, 1997. Additional credited service can be accrued under the Retirement Plan up to a limit determined by age and years of service. The Company contributions to the 401(k) plan consist of a 3 percent non-matching contribution, and a 75 percent match on the first 6 percent contributed by the employee on a before-tax basis. The Company contributed $9.0, $8.9 and $8.4 million in the years ended December 31, 2001, 2000 and 1999, respectively. The following sets forth the pension plan's funded status, components of pension costs and amounts (in thousands) at the plan valuation date of September 30:
Pension Benefits -------------------------- 2001 2000 ------------ ------------ Change in Benefit Obligation: Benefit obligation at beginning of year............... $313,152 $331,061 Service cost.......................................... 5,544 6,491 Interest cost......................................... 25,758 23,572 Amendments............................................ 3,560 - Actuarial gain (loss)................................. 44,420 (30,934) Benefits paid......................................... (19,000) (17,038) ------------ ------------ Benefit obligation at end of period............... 373,434 313,152 ------------ ------------ Change in Plan Assets: Fair value of plan assets at beginning of year........ 389,827 361,640 Actual return on plan assets.......................... (30,989) 45,225 Benefits paid......................................... (19,000) (17,038) ------------ ------------ Fair value of plan assets at end of year.......... 339,838 389,827 ------------ ------------ Funded Status......................................... (33,596) 76,675 Unamortized transition assets......................... - (1,158) Unrecognized net actuarial gain (loss)................ 48,432 (57,445) Unrecognized prior service cost....................... 3,571 44 ------------ ------------ Prepaid pension cost.............................. $18,407 $18,116 ============ ============ Weighted - Average Assumptions as of September 30, Discount rate......................................... 7.50% 8.25% Expected return on plan assets........................ 7.75% 9.00%
F-39 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999
Pension Benefits ----------------------------------- 2001 2000 1999 ---------- ----------- ---------- Components of Net Periodic Benefit Cost: Service cost.................................. $ 5,544 $ 6,491 $ 7,407 Interest cost................................. 25,758 23,572 21,777 Expected return on plan assets................ (29,488) (30,923) (27,466) Amortization of prior service cost............ (1,971) (1,130) (1,130) ---------- ----------- ---------- Net periodic pension costs (benefit)...... $ (157) $ (1,990) $ 588 ========== =========== ==========
Other Postretirement Benefits The Company provides medical and dental benefits to eligible retirees. Currently, retirees are offered the same benefits as active employees after reflecting Medicare coordination. The following sets forth the plan's funded status, components of net periodic benefit cost (in thousands) at the plan valuation date of September 30:
Other Benefits ------------------------------ 2001 2000 ------------- --------------- Change in Benefit Obligation: Benefit obligation at beginning of year.............. $ 81,711 $ 73,765 Service cost......................................... 2,644 1,053 Interest cost........................................ 7,906 5,428 Actuarial loss....................................... 17,147 1,465 ------------- --------------- Benefit obligation at end of period.............. 109,408 81,711 ------------- --------------- Change in Plan Assets: Fair value of plan assets at beginning of year....... 44,693 41,825 Actual return on plan assets.......................... (5,161) 3,661 Employer contribution................................ 6,153 1,431 Benefits paid........................................ (3,553) (2,224) ------------- --------------- Fair value of plan assets at end of year......... 42,132 44,693 ------------- --------------- Funded Status........................................ (67,276) (37,018) Unamortized transition assets........................ 19,988 3,181 Unrecognized prior service cost...................... 31,763 21,805 ------------- --------------- Accrued postretirement costs.................... $ (15,525) $ (12,032) ============= =============== Weighted - Average Assumptions as of September 30, Discount rate........................................ 7.50% 8.25% Expected return on plan assets....................... 8.25% 9.00%
F-40 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999
Other Benefits --------------------------------------- 2001 2000 1999 ----------- ------------ ------------ Components of Net Periodic Benefit Cost: Service cost........................................ $ 2,644 $ 1,053 $ 1,402 Interest cost....................................... 7,906 5,428 4,782 Expected return on plan assets...................... (3,412) (3,572) (3,135) Amortization of prior service cost.................. 2,616 1,817 1,817 ----------- ------------ ------------ Net periodic post retirement benefit cost....... $ 9,754 $ 4,726 $ 4,866 =========== ============ ============
The effect of a 1% increase in the health care trend rate assumption would increase the accumulated postretirement benefit obligation as of September 30, 2001, by approximately $18.5 million and the aggregate service and interest cost components of net periodic postretirement benefit cost for 2001 by approximately $2.0 million. The health care cost trend rate is expected to decrease to 6.0% by 2010 and to remain at that level thereafter. Executive Retirement Program The Company has an executive retirement program for a group of management employees. The program was intended to attract, motivate and retain key management employees. The Company's projected benefit obligation and accumulated benefit obligation for this program, as of the plan valuation date of September 30, 2001 and 2000, was $17.7 million and $16.9 million, respectively. As of December 31, 2001 and 2000, the Company has recognized an additional liability of $2.8 million and $2.0 million respectively, for the amount of unfunded accumulated benefits in excess of accrued pension costs. The net periodic cost for 2001, 2000 and 1999 was $1.7 million, $1.9 million and $2.3 million, respectively. In 1989, the Company established an irrevocable grantor trust in connection with the executive retirement program. Under the terms of the trust, the Company may, but is not obligated to, provide funds to the trust, which was established with an independent trustee, to aid it in meeting its obligations under the program. Marketable securities in the amount of approximately $10.2 million (fair market value of $10.9 million) are presently in trust. No additional funds have been provided to the trust since 1989. (9) Stock Option Plans The Company's Performance Stock Plan ("PSP") expired on December 31, 2000. The PSP was a non-qualified stock option plan, covering a group of management employees. Options to purchase shares of the Company's common stock were granted at the fair market value of the shares on the date of the grant. Options granted through December 31, 1995 vested on June 30, 1996 and have an exercise term of up to 10 years. All subsequent awards granted between December 31, 1995 and February 2000, vest three years from the grant date of the awards. Options granted or approved on or after February 9, 1998, can also vest upon retirement. Awards granted in December 2000 vest ratably over three years on the anniversary of the grant date. The maximum number of options authorized was 5.0 million shares that could be granted through December 31, 2000. Although the authority to grant options under the PSP expired on December 31, 2000, the options that were granted continue to be effective according to their terms. F-41 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 A new employee stock incentive plan, the Omnibus Performance Equity Plan (the "Omnibus Plan"), became effective on the formation of the holding company on December 31, 2001. The Omnibus Plan provides for the granting of non-qualified stock options, incentive stock options, restricted stock rights, performance shares, performance units and stock appreciation rights to officers and key employees. The total number of shares of common stock subject to awards under the Omnibus Plan may not exceed 2.5 million, subject to adjustment under certain circumstances defined in the Omnibus Plan. In addition, the grant of restricted stock rights, performance shares and units and stock appreciation rights is limited to 500,000 shares. Re-pricing of stock options is prohibited unless specific shareholder approval is obtained. No grants were made in 2001. Stock options may also be provided to non-employee directors of the Company under the Company's Director Retainer Plan ("DRP"). Prior to December 31, 2001, non-employee directors could elect to receive payment of the annual retainer in the form of cash, restricted stock or options to purchase shares of the Company's common stock. The number of options granted in 2001 and 2000 under this DRP was 6,000 shares with an exercise price of $22.61 and 6,000 shares with an exercise price of $6.19, respectively. 4,000 options were exercised under this DRP during both 2001 and 2000. The number of options outstanding as of December 31, 2001, was 33,000. Restricted Stock issuances were based on the fair market value of the Company's common stock on the date of grant and vest ratably three years on the anniversary of the grant date. As of December 31, 2001, there were no restricted stock outstanding under the DRP plan. Amendments to the DRP were approved by the shareholders on July 3, 2001 and the amended plan became the DRP for the new holding company on December 31, 2001. Under the new DRP, the maximum number of authorized shares was increased from 100,000 to 200,000 (including shares previously granted) through July 1, 2005. The annual retainer is payable in cash and stock options. Restricted stock is no longer available under the plan. The exercise price of stock options granted under the DRP is determined by the fair market value of the stock on the grant date. (Intentionally left blank) F-42 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 A summary of the status of the Company's stock option plans at December 31, and changes during the years then ended is presented below. Prior periods have been restated for comparability purposes.
2001 2000 1999 ---------------------- ---------------------- ---------------------- Weighted Weighted Weighted Average Average Average Exercise Exercise Exercise Fixed Options Shares Price Shares Price Shares Price - ------------------------------------ ----------- --------- ----------- ---------- ----------- ---------- Outstanding at beginning of year.... 3,336,221 $19.120 1,574,418 $18.187 1,014,242 $18.819 Granted............................. 6,000 $22.610 2,078,500 $19.403 608,708 $17.397 Exercised........................... 299,951 $19.610 296,027 $16.290 - N/A Forfeited........................... 60,969 $17.961 20,670 $17.320 48,532 $18.649 ------------ ----------- ------------ Outstanding at end of year.......... 2,981,301 3,336,221 1,574,418 ============ =========== ============ Options exercisable at year-end .... 981,197 916,263 766,454 ============ =========== ============ ptions available for future grant .. 2,500,000 - 2,183,624 ============ =========== ============
The following table summarizes information about stock options outstanding at December 31, 2001:
Options Outstanding Options Exercisable ----------------------------------------------- --------------------------- Weighted- Average Weighted Weighted Range of Number Remaining Average Number Average Exercise Outstanding Contractual Exercise Exercisable Exercise Prices At 12/31/01 Life Prices At 12/31/01 Prices - ----------------- ---------------- -------------- ------------ ------------- ------------- $5.50 - $22.61 33,000 7.136 years $ 11.020 27,000 $ 8.444 $11.50 - $24.313 2,948,301 7.783 years $ 19.194 954,197 $ 20.435 ------------ ----------- 2,981,301 7.776 years $ 19.103 981,197 $ 20.105 ============ ===========
F-43 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 Had compensation expense for the Company's stock options been recognized based on the fair value on the grant date under the methodology prescribed by SFAS No. 123, the effect on the Company's pro forma net earnings and pro forma earnings per share would be as follows (in thousands, except per share data):
2001 2000 1999 ----------------------- ---------------------- ----------------------- As Reported Pro forma As Reported Pro forma As Reported Pro forma ----------- ---------- ----------- --------- ------------ ---------- Net earnings: (available for common)....................... $149,847 $146,417 $100,360 $96,735 $82,569 $81,573 Net earnings per share Basic....................... $3.83 $3.74 $2.54 $2.45 $2.01 $1.99 Diluted..................... $3.77 $3.69 $2.53 $2.44 $2.01 $1.98
The following table summarizes weighted-average fair value of options granted during the year: 2001 2000 1999 ---------- --------- --------- PSP....................................... - $ 7.24 $3.89 ========== ========= ========= DRP....................................... $13.94 $ 6.98 $5.85 ========== ========= ========= Total fair market value of all options granted (in thousands)................... $ 83 $15,054 $2,384 ========== ========= ========= The fair value of each option grant is determined on the date of grant using the Black-Scholes option-pricing model with the following average assumptions: 2001 2000 1999 ---------- ---------- ---------- Dividend yield..................... 3.10% 2.98% 4.90% Expected volatility................ 33.99% 26.43% 30.29% Risk-free interest rates........... 5.38% 5.11% 6.43% Expected life...................... 10.0 10.0 10.0 (10) Construction Program and Jointly-Owned Plants The Company's construction expenditures for 2001 were approximately $264.9 million, including expenditures on jointly-owned projects. The Company's proportionate share of expenses for the jointly-owned plants is included in operating expenses in the consolidated statements of earnings. F-44 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 At December 31, 2001, the Company's interests and investments in jointly-owned generating facilities are:
Construction Plant in Accumulated Work in Composite Station (Fuel Type) Service Depreciation Progress Interest - ------------------------------- --------- -------------- ------------- ----------- (In thousands) San Juan Generating Station (Coal)..... $709,699 $371,122 $ 2,180 46.3% Palo Verde Nuclear Generating Station (Nuclear)*................... $210,718 $ 59,932 $21,163 10.2% Four Corners Power Plant Units 4 and 5 (Coal) ....................... $118,497 $ 81,237 $ 3,187 13.0%
* Includes the Company's interest in PVNGS Unit 3, the Company's interest in common facilities for all PVNGS units and the Company's owned interests in PVNGS Units 1 and 2. San Juan Generating Station ("SJGS") The Company operates and jointly owns SJGS. At December 31, 2001, SJGS Units 1 and 2 are owned on a 50% shared basis with Tucson Electric Power Company, Unit 3 is owned 50% by the Company, 41.8% by Southern California Public Power Authority ("SCPPA") and 8.2% by Tri-State Generation and Transmission Association, Inc. Unit 4 is owned 38.457% by the Company, 28.8% by M-S-R Public Power Agency, ("M-S-R"), 10.04% by the City of Anaheim, California, 8.475% by the City of Farmington, 7.2% by the County of Los Alamos, and 7.028% by Utah Associated Municipal Power Systems. Palo Verde Nuclear Generating Station ("PVNGS") The Company is a participant in the three 1,270 MW units of PVNGS, also known as the Arizona Nuclear Power Project, with Arizona Public Service Company ("APS") (the operating agent), Salt River Project, El Paso Electric Company ("El Paso"), Southern California Edison Company, SCPPA and The Department of Water and Power of the City of Los Angeles. The Company has a 10.2% undivided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases. (See Note 11 for additional discussion.) (11) Commitments and Contingencies Long-Term Power Contracts PNM has a power purchase contract with Southwestern Public Service Company ("SPS"), which originally provided for the purchase of up to 200 MW, expiring in May 2011. PNM may reduce its purchases from SPS by 25 MW annually upon three years' notice. PNM provided such notice to reduce the purchase by 25 MW in 1999 and by an additional 25 MW in 2000. PNM also is party to a master power purchase and sale agreement with SPS, dated August 2, 1999 pursuant to which PNM has agreed to purchase 72 MW of firm power from SPS from 2002 through F-45 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 2005. PNM has 70 MW of contingent capacity obtained from El Paso under a transmission capacity for generation capacity trade arrangement through September 2004. Beginning October 2004 and continuing through June 2005, the capacity amount is 39 MW. PNM holds a PPA with Tri-State for 50 MW through June 30, 2010. In addition, PNM is interconnected with various utilities for economy interchanges and mutual assistance in emergencies. In 1996, PNM entered into a long-term Power Purchase Agreement ("PPA") for the rights to all the output of a new gas-fired generating plant for 20 years. The PPA's maximum dependable capacity is 132 MW. In July 2000, the plant went into operation. The gas turbine generating unit is operated by Delta-Person Limited Partnership ("Delta") and is located on PNM 's retired Person Generating Station site in Albuquerque, New Mexico. Primary fuel for the gas turbine generating unit is natural gas, which is provided by PNM. In addition, the unit has the capability to utilize low sulfur fuel oil in the event natural gas is not available or cost effective. For accounting purposes, the PPA is treated as an operating lease. In July 2001, PNM 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. PNM will provide varying amounts of firm power on demand to complement existing TNMP contracts. As those contracts expire, PNM 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. Coal Supply The coal requirements for the SJGS are being supplied by San Juan Coal Company ("SJCC"), a wholly-owned subsidiary of BHP Holdings, who holds certain Federal, state and private coal leases under a Coal Sales Agreement, pursuant to which SJCC will supply processed coal for operation of the SJGS until 2017. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the agreement, which contemplates the delivery of approximately 103 million tons of coal during its remaining term. That amount would supply substantially all the requirements of the SJGS through approximately 2017. Four Corners Power Plant ("Four Corners") is supplied with coal under a fuel agreement between the owners and BHP Navajo Coal Company ("BNCC"), under which BNCC agreed to supply all the coal requirements for the life of the plant. The current fuel agreement expires December 31, 2004. Negotiations for an extension have been initiated. BNCC holds a long-term coal mining lease, with options for renewal, from the Navajo Nation and operates a surface mine adjacent to Four Corners with the coal supply expected to be sufficient to supply the units for their estimated useful lives. F-46 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 Natural Gas Supply The Company contracts for the purchase of gas to serve its jurisdictional customers. These contracts are short-term in nature supplying the gas needs for the current heating season and the following off-season months. The price of gas is a pass-through, whereby the Company recovers 100% of its cost of gas. The natural gas used as fuel by Generation and Trading was delivered by Gas. 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. Construction Commitment PNM has committed to purchase five combustion turbines at a total cost of $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. PNM has expended $103.4 million as of December 31, 2001. In November 2001, PNM broke ground for a new 135 MW single cycle gas turbine plant on a site in Southern New Mexico. This facility is expected to be operational by October 2002. Currently PNM plans to expand the facility to 225 MW by the end of 2003. In February 2002, PNM also broke ground for an 80 MW, natural gas fired generating plant in southwestern New Mexico. This facility is expected to be operational by July 2002. The planned plants are part of PNM's ongoing competitive strategy of increasing generation capacity over time. The costs of the plants are not anticipated to be added to the rate base. PVNGS Liability and Insurance Matters The PVNGS participants have insurance for public liability resulting from nuclear energy hazards to the full limit of liability under Federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $200 million and the balance by an industry-wide retrospective assessment program. If losses at any nuclear power plant covered by the programs exceed the primary liability insurance limit, the Company could be assessed retrospective adjustments. The maximum assessment per reactor under the program for each nuclear incident is approximately $88.1 million, subject to an annual limit of $10 million per reactor per incident. Based upon the Company's 10.2% interest in the three PVNGS units, the Company's maximum potential assessment per incident for all three units is approximately $27.0 million, with an annual payment limitation of $3 million per incident. If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue raising measures on the nuclear industry to pay claims. Aspects of the Federal law referred to above (the "Price-Anderson Act"), which provides for payment of public liability claims in case of a catastrophic accident involving a nuclear power plant are up for renewal in August 2002. While existing nuclear power plant would continue to be covered in any event, the renewal would extend coverage to future nuclear power plants and could contain amendments that would affect existing plants. A renewal bill was passed F-47 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 by the House with unanimous consent on November 27, 2001. The House proposed a change in the annual retrospective premium limit from $10 million to $15 million per reactor per incident. Additionally, the House proposed to amend the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident, taking into account effects of inflation. On March 7, 2002 the Senate approved a Price-Anderson Act amendment as a part of the overall energy bill. The Senate version is substantially the same as the Price-Anderson Act in its current form. In the event the energy bill does not pass, it is possible that the Price-Anderson amendment would be passed as a stand-alone bill. In a report issued in 1998, the NRC had made a number of recommendations regarding the Price-Anderson Act, including a recommendation that Congress investigate whether the $200 million now available from the private insurance market for liability claims per reactor could be increased to keep pace with inflation. The Company cannot predict whether or not Congress will renew the Price-Anderson Act or act on the NRC's recommendation. However, if adopted, certain changes in the law could possibly trigger "Deemed Loss Events" under the Company's PVNGS leases, absent waiver by the lessors. Such an occurrence could require the Company to, among other things, (i) pay the lessor and the equity investor, in return for the investor's interest in PVNGS, cash in the amount as provided in the lease and (ii) assume debt obligations relating to the PVNGS lease (see Note 4). The PVNGS participants maintain "all-risk" (including nuclear hazards) insurance for nuclear property damage to, and decontamination of, property at PVNGS in the aggregate amount of $2.75 billion as of January 1, 2002, a substantial portion of which must be applied to stabilization and decontamination. The Company has also secured insurance against portions of the increased cost of generation or purchased power and business interruption resulting from certain accidental outages of any of the three units if the outages exceed 12 weeks. The insurance coverage discussed in this section is subject to certain policy conditions and exclusions. The Company is a member of an industry mutual insurer. This mutual insurer provides both the "all-risk" and increased cost of generation insurance to the Company. In the event of adverse losses experienced by this insurer, the Company is subject to an assessment. The Company's maximum share of any assessment is approximately $4.8 million per year. PVNGS Decommissioning Funding The Company has a program for funding its share of decommissioning costs for PVNGS. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. The results of the 1998 decommissioning cost study indicated that the Company's share of the PVNGS decommissioning costs excluding spent fuel disposal will be approximately $181 million (in 1998 dollars). The Company funded an additional $6.1 million, $3.9 million and $3.1 million in 2001, 2000 and 1999, respectively, into the qualified and non-qualified trust funds. The estimated market value of the trusts at the end of 2001 was approximately $57.3 million. F-48 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 Nuclear Spent Fuel and Waste Disposal Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the "Waste Act"), the United States Department of Energy ("DOE") is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by all domestic power reactors. Under the Waste Act, DOE was to develop the facilities necessary for the storage and disposal of spent nuclear fuel and to have the first such facility in operation by 1998. DOE has announced that such a repository now cannot be completed before 2010. The operator of PVNGS has capacity in existing fuel storage pools at PVNGS which, with certain modifications, could accommodate all fuel expected to be discharged from normal operation of PVNGS through 2002, and believes it could augment that storage with the new facilities for on-site dry storage of spent fuel for an indeterminate period of operation beyond 2002, subject to obtaining any required governmental approvals. The Company currently estimates that it will incur approximately $41.0 million (in 1998 dollars) over the life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. The Company accrues these costs as a component of fuel expense, meaning the charges are accrued as the fuel is burned. In 2001 and 2000, the Company expensed approximately $1.0 million for on-site interim nuclear fuel storage costs related to nuclear fuel burned during 2001 and 2000. The operator of PVNGS currently believes that spent fuel storage or disposal methods will be available for use by PVNGS to allow its continued operation beyond 2002. Natural Gas Explosion On April 25, 2001, a natural gas explosion occurred in Santa Fe, New Mexico. The apparent cause of the explosion was a leak from a Company line near the location. The explosion destroyed a small building and injured two persons who were working in the building. The Company's investigation indicates that the leak was an isolated incident likely caused by a combination of corrosion and increased pressure. The Company also is cooperating with an investigation of the incident by the PRC's Pipeline Safety Bureau which issued its report on March 18, 2002. The Bureau's report gives PNM notice of 13 possible violations of the New Mexico Pipeline Safety Act and related regulations. Two lawsuits against the Company by the injured persons along with several claims for property and business interruption damages have been resolved by the Company. At this time, the Company is unable to estimate the potential liability, if any, that the Company may incur as a result of the Pipeline Safety Bureau's investigation. There can be no assurance that the outcome of this matter will not have a material adverse impact on the results of operations and financial position of the Company. Western Resources Transaction On November 9, 2000, the Company and Western Resources announced that both companies' Boards of Directors approved an agreement under which the Company will acquire the Western Resources electric utility operations in a tax-free, stock-for-stock transaction. The agreement required that Western Resources split-off its non-utility businesses to its shareholders prior to closing. F-49 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 In July, 2001, the KCC issued two orders. The first order declared the split-off required by the agreement to be unlawful as designed, with or without a merger. The second order decreased rates for Western Resources, despite a request for $151 million increase. After rehearing the KCC established the rate decrease at $15.7 million. On October 3, 2001, the KCC issued an Order on Reconsideration reaffirming its decision that the split-off as designed in the agreement was unlawful with or without a merger. Because of these rulings, the Company announced that it believed the agreement as originally structured could not be consummated. Efforts to renegotiate the transaction failed. Western Resources demanded that the Company file for regulatory approvals of the transaction as designed, despite the fact that the transaction required the split-off already determined to be unlawful by the KCC. As a result of the disagreement over the viability of the transaction as designed, the Company filed suit on October 12, 2001, in New York state court seeking declarations that the transaction could not be accomplished as designed due to the KCC's determination that the split-off condition of the transaction is unlawful; that the Company is not obligated to pursue approvals of the transaction as designed; that the transaction is terminated effective December 31, 2001, without an automatic extension; and that the KCC rate case order constitutes a material adverse effect under the agreement. The Company also seeks monetary damages for breach of contract because Western Resources represented and warranted that the split-off did not require approval of the KCC. On November 19, 2001, Western Resources filed a complaint against the Company in New York state court alleging breach of contract and breach of implied covenant of good faith and fair dealing. Western Resources alleged that the Company brought about the KCC orders, failed to assist in efforts to reverse the KCC orders, refused to renegotiate within the terms of the agreement, interfered with Western Resources' efforts to satisfy the terms of the agreement, and effected an unauthorized de facto termination of the agreement by filing its complaint. Western Resources alleges damages in excess of $650 million. The Company believes that the complaint filed by Western Resources is without merit and intends to vigorously defend itself against the complaint. The Company also intends to vigorously pursue its own complaint. On January 7, 2002, the Company notified Western Resources that it had taken action to terminate the agreement as of that date. The Company identified numerous breaches of the agreement by Western Resources and the regulatory rulings in Kansas as reasons for the termination. On January 9, 2002, Western Resources responded that it considered the Company's termination to be ineffective and the agreement to still be in effect. On February 5, 2002, the District Court for Shawnee County, Kansas, dismissed without prejudice Western Resources' petition for judicial review of the KCC's split-off orders. The Court ruled that, by filing a new financial plan in compliance with the orders, Western Resources had acquiesced in certain portions of the orders thereby creating a situation where further administrative action became necessary. As a result, the Court concluded that the matter was not ripe for judicial review and remanded the case to the KCC. F-50 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 On March 8, 2002, the Kansas Court of Appeals affirmed the KCC's rate order. The Company is currently unable to predict the outcome of its litigation with Western Resources. Other There are various 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 known lawsuits, environmental costs and commitments will have a material adverse effect on its financial condition or results of operations. (12) 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 F-51 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued) December 31, 2001, 2000 and 1999 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 year ended December 31, 2001, 2000 and 1999, the Company spent $1.7 million, $1.6 million and $4.4 million, respectively, for remediation. The majority of the December 31, 2001, environmental liability is expected to be paid over the next five years, funded by cash generated from operations. Future environmental obligations are not expected to have a material impact on the results of operations or financial condition of the Company. (13) New and Proposed Accounting Standards Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" ("SFAS 143"). In June 2001, the FASB issued SFAS 143. The statement requires the recognition of a liability for legal obligations associated with the retirement of a tangible long-lived asset that result from the acquisition, construction or development and/or the normal operation of a long-lived asset. The asset retirement obligation is required to be recognized at its fair value when incurred. The cost of the asset retirement obligation is required to be capitalized by increasing the carrying amount of the related long-lived asset by the same amount as the liability. This cost must be expensed using a systematic and rational method over the related asset's useful life. SFAS 143 is effective for the Company beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and is unable to predict its impact on the Company's operating results and financial position at this time. Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS 144"). In August 2001, the FASB issued SFAS 144. The statement amends certain requirements of the previously issued pronouncement on asset impairment, SFAS 121. SFAS 144 removes goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a "primary asset" approach for a group of assets and liabilities that represents the unit of accounting to be evaluated for impairment. In addition, SFAS 144 changes the measurement of long-lived assets to be disposed of by sale, as accounted for by Accounting Principles Board Opinion No. 30. Under SFAS 144, discontinued operations are no longer measured on a net realizable value basis, and their future operating losses are no longer recognized before they occur. The Company does not believe SFAS 144 will have a material effect on its future operating results or financial position. F-52 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO QUARTERLY OPERATING RESULTS The unaudited operating results by quarters for 2001 and 2000 are as follows:
Quarter Ended ---------------------------------------------------- March 31 June 30 September 30 December 31 ----------- ----------- -------------- ------------ (In thousands, except per share amounts) 2001: Operating Revenues......................... $ 736,530 $ 666,091 $ 621,895 $ 327,581 Operating Income........................... 77,300 80,547 47,422 17,407 Earnings from Continuing Operations........ 63,552 49,597 32,775 4,509 Net Earnings............................... 63,552 49,597 32,775 4,509 Net Earnings per share from Continuing Operations.............................. 1.62 1.26 0.83 0.11 Net Earnings per Share (Basic)............. 1.62 1.26 0.83 0.11 Net Earnings per Share (Diluted)........... 1.60 1.24 0.82 0.11 2000: Operating Revenues......................... $ 321,291 $ 329,041 $ 499,477 $ 461,465 Operating Income........................... 30,947 27,654 47,452 26,422 Earnings from Continuing Operations........ 21,952 17,986 46,913 14,096 Net Earnings .............................. 21,952 17,986 46,913 14,096 Net Earnings per share from Continuing Operations.............................. 0.55 0.45 1.19 0.36 Net Earnings per Share (Basic)............. 0.55 0.45 1.19 0.36 Net Earnings per Share (Diluted)........... 0.55 0.45 1.18 0.35
In the opinion of management of the Company, all adjustments (consisting of normal recurring accruals) necessary for a fair statement of the results of operations for such periods have been included. - ------------------- F-53 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO COMPARATIVE OPERATING STATISTICS (Unaudited)
2001 2000 1999 1998 1997 ----------- ----------- ----------- ----------- ----------- Utility Operations Sales: Energy Sales--KWh (in thousands): Residential.............................. 2,197,889 2,171,945 2,027,589 2,022,598 1,951,219 Commercial............................... 3,213,208 3,133,996 2,981,656 2,909,752 2,805,576 Industrial............................... 1,603,266 1,544,367 1,559,155 1,571,824 1,556,264 Other ultimate customers................. 240,934 238,635 235,183 235,700 221,840 ----------- ----------- ----------- ----------- ----------- Total KWh sales........................ 7,255,297 7,088,943 6,803,583 6,739,874 6,534,899 =========== =========== =========== =========== =========== Gas Throughput--Decatherms (in thousands): Residential.............................. 27,848 28,810 32,121 29,258 30,605 Commercial............................... 10,421 9,859 11,106 10,044 10,592 Industrial............................... 3,920 5,038 2,338 1,553 1,280 Other.................................... 4,355 6,426 6,538 8,390 8,158 ----------- ----------- ----------- ----------- ----------- Total gas sales........................ 46,544 50,133 52,103 49,245 50,635 Transportation throughput................ 51,395 44,871 40,161 36,413 33,975 ----------- ----------- ----------- ----------- ----------- Total gas throughput................... 97,939 95,004 92,264 85,658 84,610 =========== =========== =========== =========== =========== Revenues (in thousands): Electric Revenues: Residential.............................. $ 187,600 $ 186,133 $ 184,088 $ 187,681 $ 184,813 Commercial............................... 242,372 238,243 238,830 241,968 237,629 Industrial............................... 82,752 79,671 85,828 88,644 86,927 Other ultimate customers................. 14,795 14,618 13,777 18,124 10,135 ----------- ----------- ----------- ----------- ----------- Total revenues to ultimate customers... 527,519 518,665 522,523 536,417 519,504 Intersegment revenues.................... 707 707 707 707 - Miscellaneous electric revenues.......... 31,707 20,093 18,345 19,151 3,331 ----------- ----------- ----------- ----------- ----------- Total electric revenues................ $ 559,933 $ 539,465 $ 541,575 $ 556,275 $ 522,835 ----------- ----------- ----------- ----------- ----------- Gas Revenues: Residential.............................. $ 232,321 $ 191,231 $ 152,266 $ 160,398 $ 185,851 Commercial............................... 68,895 52,964 37,337 42,480 50,042 Industrial............................... 27,519 24,206 8,550 4,887 4,533 Other.................................... 28,896 29,203 20,080 27,218 30,285 ----------- ----------- ----------- ----------- ----------- Revenues from gas sales.................. 357,631 297,604 218,233 234,983 270,711 Transportation........................... 20,188 14,163 12,390 13,464 14,172 Other.................................... 7,599 8,157 6,088 7,528 9,886 ----------- ----------- ----------- ----------- ----------- Total gas revenues..................... $ 385,418 $ 319,924 $ 236,711 $ 255,975 $ 294,769 ----------- ----------- ----------- ----------- ----------- Total Utility Revenues............ $ 945,351 $ 859,389 $ 778,286 $ 812,250 $ 817,604 =========== =========== =========== =========== ===========
F-54 PNM RESOURCES, INC. AND SUBSIDIARIES AND PUBLIC SERVICE COMPANY OF NEW MEXICO COMPARATIVE OPERATING STATISTICS (Unaudited)
2001 2000 1999 1998 1997 ------------ ------------ ------------ ----------- ----------- Utility Customers at Year End: Electric: Residential............................. 336,614 328,519 321,949 319,415 311,314 Commercial.............................. 39,674 38,991 38,435 37,652 36,942 Industrial.............................. 377 371 375 363 363 Other ultimate customers................ 924 625 625 665 637 ------------ ------------ ------------ ----------- ----------- Total ultimate customers.............. 377,589 368,506 361,384 358,095 349,256 Sales for Resale........................ 79 81 83 83 66 ------------ ------------ ------------ ----------- ----------- Total customers....................... 377,668 368,587 361,467 358,178 349,322 ============ ============ ============ =========== =========== Gas: Residential............................. 404,753 398,623 390,428 383,292 375,032 Commercial.............................. 32,894 32,626 32,116 32,004 31,560 Industrial.............................. 50 50 51 55 50 Other................................... 3,528 3,612 3,688 3,622 3,765 Transportation.......................... 34 32 32 29 31 ------------ ------------ ------------ ----------- ----------- Total customers....................... 441,259 434,943 426,315 419,002 410,438 ============ ============ ============ =========== =========== Generation and Trading Operations Sales: Energy Sales--KWh (in thousands): Firm-requirements wholesale............. 616,703 330,003 179,249 278,615 278,727 Other contracted off-system............. 6,900,589 7,315,679 6,196,499 4,033,931 3,790,081 Economy energy sales.................... 5,059,808 4,706,446 4,795,873 4,469,769 2,716,835 ------------ ------------ ------------ ----------- ----------- Total sales to ultimate customers..... 12,577,100 12,352,128 11,171,621 8,782,315 6,785,643 Intersegment sales...................... 7,255,297 7,088,943 6,803,583 6,739,874 6,534,899 ------------ ------------ ------------ ----------- ----------- Total energy sales.................... 19,832,397 19,441,071 17,975,204 15,522,189 13,320,542 ============ ============ ============ =========== =========== Revenues (in thousands): Firm-requirements wholesale............. $ 24,754 $ 15,540 $ 7,046 $ 10,708 $ 10,690 Other contracted off-system............. 892,105 364,278 226,773 142,115 118,876 Economy energy sales.................... 512,209 368,374 131,549 122,156 55,768 ------------ ------------ ------------ ----------- ----------- Total revenues to ultimate customers.. 1,429,068 748,192 365,368 274,979 185,334 Intersegment revenues................... 341,608 324,744 318,872 362,722 370,019 Miscellaneous electric revenues......... (23,152) 2,242 5,741 4,657 14,269 ------------ ------------ ------------ ----------- ----------- Total generation revenues............. $1,747,524 $1,075,178 $ 689,981 $ 642,358 $ 569,622 ============ ============ ============ =========== =========== Customers at Year End: Generation 79 81 83 83 66 ============ ============ ============ =========== =========== Reliable Net Capability--KW............... 1,521,000 1,521,000 1,521,000 1,506,000 1,506,000 Coincidental Peak Demand--KW.............. 1,397,000 1,368,000 1,291,000 1,313,000 1,209,000 Average Fuel Cost per Million BTU......... $ 1.6007 $ 1.3827 $ 1.3169 $ 1.2433 $ 1.2319 BTU per KWh of Net Generation............. 10,549 10,547 10,490 10,784 10,927
F-55 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of PNM Resources, Inc. and Public Service Company of New Mexico: We have audited, in accordance with auditing standards generally accepted in the United States, the consolidated financial statements included in this annual report on Form 10-K, and have issued our report thereon dated February 1, 2002. Our audit was made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed in the index are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic consolidated financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole. Albuquerque, New Mexico February 1, 2002 F-56 SCHEDULE I The PNM Resources, Inc. holding company structure was effected through a one-for-one share exchange between the shareholders of Public Service Company of New Mexico ("PNM") and PNM Resources, Inc. on December 31, 2001, whereby the shareholders of PNM became shareholders of PNM Resources, Inc. and PNM Resources, Inc. acquired all of PNM's common stock. There were no material operations in 2001; therefore a statement of earnings is not presented. PNM RESOURCES, INC. CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY BALANCE SHEET As of December 31, ------------------ 2001 --------------- (In thousands) Assets Cash and cash equivalents................................ $ 11,380 Other current assets..................................... 9,951 --------------- Total current assets.................................. 21,331 --------------- Investment in subsidiaries............................... 885,328 Other investments........................................ 105,669 --------------- Total Assets........................................... $ 1,012,328 =============== Liabilities and Shareholder's Equity Common stock, 39,118 shares, issued and authorized....... $ 195,589 Additional paid in capital............................... 816,739 Retained earnings........................................ - --------------- Total Liabilities and Shareholder's Equity............ $ 1,012,328 =============== F-57 SCHEDULE I PNM RESOURCES, INC. CONDENSED FINANCIAL INFORMATION OF PARENT COMPANY STATEMENT OF CASH FLOWS As of December 31, ------------------ 2001 --------------- (In thousands) Net cash provided by investing activities: Cash dividends received from subsidiaries................... $ 127,000 Short-term and long-term investments........................ (115,620) --------------- Net increase in cash and cash equivalents..................... 11,380 Cash and cash equivalents at beginning of period.............. - --------------- Cash and cash equivalents at end of period.................... $ 11,380 =============== F-58 SCHEDULE II PNM RESOURCES, INC. PUBLIC SERVICE COMPANY OF NEW MEXICO VALUATION AND QUALIFYING ACCOUNTS
Additions Deductions -------------------------------- ----------- Balance at Charged to Charged to beginning of costs and other Write off Balance at Description year expenses accounts adjustments end of year - ----------------------------------- ------------- --------------- -------------- ----------- ----------- (In thousands) Allowance for doubtful accounts, year ended December 31: 1999 $ 836 $11,496 $ - $ (172) $ 12,504 2000 $12,504 $14,296 $ - $13,521 $ 13,279 2001 $13,279 $10,312 $ - $ 5,566 $ 18,025 Allowance for market and credit volatility year ended December 31: 1999 $ - $ - $ - $ - $ - 2000 $ - $ 4,139 $ - $ - $ 4,139 2001 $ 4,139 $(1,090) (a) $ - $ - $ 3,049
(a) Represents a change in assessed market and credit volatility risk by the Company (see Management's Discussion and Analysis of Results of Operations and Financial Condition - Critical Accounting Policies). F-59 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY Reference is hereby made to "Election of Directors" in the Company's Proxy Statement relating to the annual meeting of stockholders to be held on May 14, 2002 (the "2002 Proxy Statement"), to PART I, SUPPLEMENTAL ITEM - "EXECUTIVE OFFICERS OF THE COMPANY" and "Other Matters" - "Section 16(a) Beneficial Ownership Reporting Compliance" in the 2002 Proxy Statement. ITEM 11. EXECUTIVE COMPENSATION Reference is hereby made to "Executive Compensation" in the 2002 Proxy Statement. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Reference is hereby made to "Voting Information", "Election of Directors" and "Stock Ownership of Certain Executive Officers" in the 2002 Proxy Statement. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Reference is hereby made to the 2002 Proxy Statement for such disclosure, if any, as may be required by this item. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) - 1. See Index to Financial Statements under Item 8. (a) - 2. Financial Statement Schedules for the years 2001, 2000, and 1999 are omitted for the reason that they are not required or the information is otherwise supplied. (a) - 3-A. Exhibits Filed: E-1 Exhibit Description - ------- ----------- No. - --- 3.1 Restated Articles of Incorporation of PNM Resources dated February 22, 2002 10.52** PNM Resources' Executive Spending Account procedures effective January 1, 2002 10.75** First Amended and Restated Public Service Company of New Mexico Executive Savings Plan dated November 16, 2001 21 Certain subsidiaries of PNM Resources 23.1 Consent of Arthur Andersen LLP 99.23 Confirmation of Arthur Andersen LLP's representation of audit quality control (a) - 3-B. Exhibits Incorporated By Reference: In addition to those Exhibits shown above, PNM and PNM Resources hereby incorporate the following Exhibits pursuant to Exchange Act Rule 12b-32 and Regulation S-K section 10, paragraph (d) by reference to the filings set forth below:
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- Articles of Incorporation and By-laws 3.1.1 Restated Articles of Incorporation of PNM, as 4-(b) to PNM's Registration 2-99990 amended through May 10, 1985 Statement 3.2 Bylaws of PNM Resources, Inc. with all 4.2 of Post-Effective Amendment 333-10993 Amendments to and including April 17, 2001 No. 1 to PNM Resources Form S-3 Registration Statement filed October 4, 2001
E-2
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- Instruments Defining the Rights of Security Holders, Including Indentures 3.2.1 By-laws of PNM with All Amendments to and 3.2 to PNM's Annual Report on 1-6986 including February 8, 2000 Form 10-K for the fiscal year ended December 31, 2000 4.1 Indenture of Mortgage and Deed of Trust dated as 4-(d) to PNM's Registration 2-99990 of June 1, 1947, between PNM and The Bank of New Statement No. 2-99990 York (formerly Irving Trust Company), as Trustee, together with the Ninth Supplemental Indenture dated as of January 1, 1967, the Twelfth Supplemental Indenture dated as of September 15, 1971, the Fourteenth Supplemental Indenture dated as of December 1, 1974 and the Twenty-Second Supplemental Indenture dated as of October 1, 1979 thereto relating to First Mortgage Bonds of PNM 4.3 Fifty-third Supplemental Indenture, dated as of 4.3 to PNM's Quarterly Report 1-6986 March 11, 1998, supplemental to Indenture of on Form 10-Q for the quarter Mortgage and Deed of Trust, dated as of June 1, ended March 31, 1998. 1947, between PNM and The Bank of New York(formerly Irving Trust Company), as trustee. 4.4 Indenture (for Senior Notes), dated as of March 4.4 to PNM's Quarterly Report 1-6986 11, 1998, between PNM and The Chase Manhattan on Form 10-Q for the quarter Bank, as Trustee. ended March 31, 1998. 4.5 First Supplemental Indenture, dated as of March 4.5 to PNM's Quarterly Report 1-6986 11, 1998, supplemental to Indenture, dated as of on Form 10-Q for the quarter March 11, 1998, Between PNM and The Chase ended March 31, 1998. Manhattan Bank, as Trustee. 4.6 Second Supplemental Indenture, dated as of March 4.6 to PNM's Quarterly Report 1-6986 11, 1998, supplemental to Indenture, dated as of on Form 10-Q for the quarter March 11, 1998, Between PNM and The Chase ended March 31, 1998. Manhattan Bank, as Trustee.
E-3
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 4.6.1 Third Supplemental Indenture, dated as of 4.6.1 to PNM's Annual Report on 1-6986 October 1, 1999 to Indenture dated as of March Form 10-K for the fiscal year 11, 1998, between PNM and The Chase Manhattan ended December 31, 1999. Bank, as Trustee 4.7 Indenture (for Senior Notes), dated as of August 4.1 to PNM's Registration 33-53367 1, 1998, between PNM and The Chase Manhattan Statement No. 33-53367 Bank, as Trustee. 4.8 First Supplemental Indenture, dated August 1, 4.3 to PNM's Current Report on 1-6986 1998, supplemental to Indenture, dated as of Form 8-K dated August 7, 1998. August 1, 1998, between PNM and the Chase Manhattan Bank, as Trustee. Material Contracts 10.1 Supplemental Indenture of Lease dated as of July 4-D to PNM's Registration 2-26116 19, 1966 between PNM and other participants in Statement No. 2-26116 the Four Corners Project and the Navajo Indian Tribal Council. 10.1.1 Amendment and Supplement No. 1 to Supplemental 10.1.1 to PNM's Annual Report 1-6986 and Additional Indenture of Lease dated April on Form 10-K for fiscal year 25, 1985 between the Navajo Tribe of Indians and ended December 31, 1995. Arizona Public Service Company, El Paso Electric Company, Public Service Company of New Mexico, Salt River Project Agricultural Improvement and Power District, Southern California Edison Company, and Tucson Electric Power Company (refiled). 10.2 Fuel Agreement, as supplemented, dated as of 4-H to PNM's Registration 2-35042 September 1, 1966 between Utah Construction & Statement No. 2-35042 Mining Co. and the participants in the Four Corners Project including PNM. 10.3 Fourth Supplement to Four Corners Fuel Agreement 10.3 to PNM's Annual Report on 1-6986 No. 2 effective as of January 1, 1981, between Form 10-K for fiscal year ended Utah International Inc. and the participants in December 31, 1991. the Four Corners Project, including PNM. 10.4 Contract between the United States and PNM dated 5-L to PNM's Registration 2-41010 April 11, 1968, for furnishing water. Statement No. 2-41010
E-4
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.4.1 Amendatory Contract between the United States 5-R to PNM's Registration 2-60021 and PNM dated September 29, 1977, for furnishing Statement No. 2-60021 water. 10.5 Water Supply Agreement between the Jicarilla 10.5 to PNM's Quarterly Report 1-6986 Apache Tribe and Public Service Company of New of Form 10-Q for the quarter Mexico, dated July 20, 2000 ended September 30, 2001 10.8 Arizona Nuclear Power Project Participation 5-T to PNM's Registration 2-50338 Agreement among PNM and Arizona Public Service Statement No. 2-50338 Company, Salt River Project Agricultural Improvement and Power District, Tucson Gas & Electric Company and El Paso Electric Company, dated August 23, 1973. 10.8.1 Amendments No. 1 through No. 6 to Arizona 10.8.1 to PNM's Annual Report 1-6986 Nuclear Power Project Participation Agreement. on Form 10-K for fiscal year ended December 31, 1991. 10.8.2 Amendment No. 7 effective April 1, 1982, to the 10.8.2 to PNM's Annual Report 1-6986 Arizona Nuclear Power Project Participation on Form 10-K for fiscal year Agreement (refiled). ended December 31, 1991. 10.8.3 Amendment No. 8 effective September 12, 1983, to 10.58 to PNM's Annual Report on 1-6986 the Arizona Nuclear Power Project Participation Form 10-K for fiscal year ended Agreement (refiled). December 31, 1993. 10.8.4 Amendment No. 9 to Arizona Nuclear Power Project 10.8.4 to PNM's Annual Report 1-6986 Participation Agreement dated as of June 12, of the Registrant on Form 10-K 1984 (refiled). for fiscal year ended December 31, 1994. 10.8.5 Amendment No. 10 dated as of November 21, 1985 10.8.5 to PNM's Annual Report 1-6986 and Amendment No. 11 dated as of June 13, 1986 of the Registrant on Form 10-K and effective January 10, 1987 to Arizona for fiscal year ended December Nuclear Power Project Participation Agreement 31, 1994. (refiled).
E-5
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.8.7 Amendment No. 12 to Arizona Nuclear Power 19.1 to PNM's Quarterly Report 1-6986 Project Participation Agreement dated June 14, on Form 10-Q for the quarter 1988, and effective August 5, 1988. ended September 30, 1990. 10.8.8 Amendment No. 13 to the Arizona Nuclear Power 10.8.10 to PNM's Annual Report 1-6986 Project Participation Agreement dated April 4, on Form 10-K for the fiscal 1990, and effective June 15, 1991. year ended December 31, 1990. 10.8.9 Amendment No. 14 to the Arizona Nuclear Power 10.8.9 to PNM's Annual Report Project Participation Agreement effective June on Form 10-K for the fiscal 20, 2000. year ended December 31, 2000. 10.9 Coal Sales Agreement executed August 18, 1980 10.9 to PNM's Annual Report for 1-6986 among San Juan Coal Company, PNM and Tucson fiscal year ended December 31, Electric Power Company, together with Amendments 1991. No. One, Two, Four, and Six thereto. 10.9.1 Amendment No. Three to Coal Sales Agreement 10.9.1 to PNM's Annual Report 1-6986 dated April 30, 1984 among San Juan Coal on Form 10-K for fiscal year Company, PNM and Tucson Electric Power Company. ended December 31, 1994 (confidentiality treatment was requested at the time of filing the Annual Report of the Registrant on Form 10-K for fiscal year ended December 31, 1984; exhibit was not filed therewith based on the same confidentiality request). 10.9.2 Amendment No. Five to Coal Sales Agreement dated 10.9.2 to PNM's Annual Report 1-6986 May 29, 1990 among San Juan Coal Company, PNM on Form 10-K for fiscal year and Tucson Electric Power Company. ended December 31, 1991 (confidentiality treatment was requested as to portions of this exhibit, and such portions were omitted from the exhibit filed and were filed separately with the Securities and Exchange Commission).
E-6
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.9.3 Amendment No. Seven to Coal Sales Agreement, 19.3 to PNM's Quarterly Report 1-6986 dated as of July 27, 1992 among San Juan Coal on Form 10-Q for the quarter Company, PNM and Tucson Electric Power Company. ended September 30, 1992 (confidentiality treatment was requested as to portions of this exhibit, and such portions were omitted from the exhibit filed and were filed separately with the Securities and Exchange Commission). 10.9.4 First Supplement to Coal Sales Agreement, dated 19.4 to PNM's Quarterly Report 1-6986 July 27, 1992 among San Juan Coal Company, PNM on Form 10-Q for the quarter and Tucson Electric Power Company. ended September 30, 1992 (confidentiality treatment was requested as to portions of this exhibit, and such portions were omitted from the exhibit filed and were filed separately with the Securities and Exchange Commission). 10.9.5 Amendment No. Eight to Coal Sales Agreement, 10.9.5 to PNM's Annual Report 1-6986 dated as of September 1, 1995, among San Juan on Form 10-K for fiscal year Coal Company, PNM and Tucson Electric Power ended December 31, 1995. Company. 10.9.6 Amendment No. Nine to Coal Sales Agreement, 10.9.6 to PNM's Annual Report 1-6986 dated as of December 31, 1995, among San Juan of the Registrant on Form 10-K Coal Company, PNM and Tucson Electric Power for fiscal year ended December Company. 31, 1996.
E-7
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.9.8 Amendment No. 11 to Coal Sales Agreement, dated 10.9.8 to PNM's Quarterly August 31, 2001 among San Juan Coal Company, PNM Report on Form 10-Q for the and Tucson Electric Power Company quarter ended September 30, 2001.(confidentiality treatment was requested as to portions of this exhibit, and such portions were omitted from the exhibit filed and were filed separately with the Securities and Exchange Commission). 10.11 San Juan Unit 4 Early Purchase and Participation 10.11 to PNM's Quarterly Report 1-6986 Agreement dated as of September 26, 1983 between on Form 10-Q for the quarter PNM and M-S-R Public Power Agency, and ended March 31, 1994. Modification No. 2 to the San Juan Project Agreements dated December 31, 1983 (refiled). 10.11.1 Amendment No. 1 to the Early Purchase and 10.11.1 to PNM's Annual Report 1-6986 Participation Agreement between Public Service on Form 10-K for fiscal year Company of New Mexico and M-S-R Public Power ended December 31, 1997. Agency, executed as of December 16, 1987, for San Juan Unit 4 (refiled). 10.11.3 Amendment No. 3 to the San Juan Unit 4 Early 10.11.3 to PNM's Annual Report 1-6986 Purchase and Participation Agreement between on Form 10-K for fiscal year Public Service Company of New Mexico and M-S-R ended December 31, 1999. Public Power Agency, dated as of October 27, 1999. 10.12 Amended and Restated San Juan Unit 4 Purchase 10.12 to PNM's Annual Report on 1-6986 and Participation Agreement dated as of December Form 10-K for fiscal year ended 28, 1984 between PNM and the Incorporated December 31, 1994. County of Los Alamos (refiled). 10.12.1 Amendment No. 1 to the Amended and Restated San 10.12.1 to PNM's Annual Report 1-6986 Juan Unit 4 Purchase and Participation Agreement Form 10-K for fiscal year ended between Public Service Company of New Mexico and December 31, 1999. M-S-R Public Power Agency, dated as of October 27, 1999.
E-8
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.13 Amendment No. 2 to the San Juan Unit 4 Purchase 10.13 to PNM's Annual Report on 1-6986 Agreement and Participation Agreement between Form 10-K for fiscal year ended Public Service Company of New Mexico and The December 31, 1999. Incorporated County of Los Alamos, New Mexico, dated October 27, 1999. 10.14 Participation Agreement among PNM, Tucson 10.14 to PNM's Annual Report on 1-6986 Electric Power Company and certain financial Form 10-K for fiscal year ended institutions relating to the San Juan Coal Trust December 31, 1992. dated as of December 31, 1981 (refiled). 10.16 Interconnection Agreement dated November 23, 10.16 to PNM's Annual Report on 1-6986 1982, between PNM and Southwestern Public Form 10-K for fiscal year ended Service Company (refiled). December 31, 1992. 10.18* Facility Lease dated as of December 16, 1985 10.18 to PNM's Annual Report on 1-6986 between The First National Bank of Boston, as Form 10-K for fiscal year ended Owner Trustee, and Public Service Company of New December 31, 1995. Mexico together with Amendments No. 1, 2 and 3 thereto (refiled). 10.18.4* Amendment No. 4 dated as of March 8, 1995, to 10.18.4 to the PNM's Quarter 1-6986 Facility Lease between Public Service Company of Report on Form New Mexico and the First National Bank of 10-Q for the quarter ended Boston, dated as of December 16, 1985. March 31, 1995. 10.19 Facility Lease dated as of July 31, 1986, 10.19 to PNM's Annual Report on 1-6986 between the First National Bank of Boston, as Form 10-K for fiscal year ended Owner Trustee, and Public Service Company of New December 31, 1996. Mexico together with Amendments No. 1, 2 and 3 thereto (refiled). 10.20* Facility Lease dated as of August 12, 1986, 10.20 to PNM's Annual Report on 1-6986 between The First National Bank of Boston, as Form 10-K for fiscal year ended Owner Trustee, and Public Service Company of New December 31, 1996. Mexico together with Amendments No. 1 and 2 thereto (refiled).
E-9
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.20.2 Amendment No. 2 dated as of April 10, 1987 to 10.20.2 to PNM's Annual 1-6986 Facility Lease dated as of August 12, 1986, as Report on Form 10-K for amended, between The First National Bank of Boston, fiscal year ended December not in its individual capacity, but solely as Owner 31, 1998. Trustee under a Trust Agreement, dated as of August 12, 1986, with MFS Leasing Corp., Lessor and Public Service Company of New Mexico, Lessee (refiled). 10.20.3 Amendment No. 3 dated as of March 8, 1995, to 10.20.3 to PNM's Quarterly 1-6986 Facility Lease between Public Service Company of New Report on Form Mexico and the First National Bank of Boston, dated 10-Q for the quarter ended as of August 12, 1986. March 31, 1995. 10.21 Facility Lease dated as of December 15, 1986, 10.21 to PNM's Annual Report 1-6986 between The First National Bank of Boston, as Owner on Form 10-K for fiscal year Trustee, and Public Service Company of New Mexico ended December 31, 1996. (Unit 1 Transaction) together with Amendment No. 1 thereto (refiled). 10.22 Facility Lease dated as of December 15, 1986, 10.22 to PNM's Annual Report 1-6986 between The First National Bank of Boston, as Owner of the Registrant on Form Trustee, and Public Service Company of New Mexico 10-K for fiscal year ended Unit 2 Transaction) together with Amendment No. 1 December 31, 1996. thereto (refiled). 10.23** Restated and Amended Public Service Company of New 10.23 to PNM's Annual Report 1-6986 Mexico Accelerated Management Performance Plan on Form 10-K for fiscal year (1988) (August 16, 1988) (refiled). ended December 31, 1998. 10.23.1** First Amendment to Restated and Amended Public 10.23.1 to PNM's Annual 1-6986 Service Company of New Mexico Accelerated Management Report on Form 10-K for Performance Plan (1988) (August 30, 1988) (refiled). fiscal year ended December 31, 1998. 10.23.2** Second Amendment to Restated and Amended Public 10.23.2 to PNM's Annual 1-6986 Service Company of New Mexico Accelerated Management Report on Form 10-K for Performance Plan (1988) (December 29, 1989) fiscal year ended December (refiled). 31, 1998.
E-10
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.23.4** Fourth Amendment to the Restated and Amended Public 10.23.4 to PNM's Quarterly 1-6986 Service Company of New Mexico Accelerated on Form 10-Q for the Management Report Performance Plan, as quarter ended March 31, 1999. amended effective December 7, 1998. 10.24** Management Life Insurance Plan (July 1985) of the 10.24 to PNM's Annual Report 1-6986 Company (refiled). on Form 10-K for fiscal year ended December 31, 1995. 10.25.1** Second Restated and Amended Public Service Company 10.25.1 to PNM's Annual 1-6986 of New Mexico Executive Medical Plan as amended on Report on Form 10-K for December 28, 1995. fiscal year ended December 31, 1997. 10.27 Amendment No. 2 dated as of April 10, 1987, to the 10.53 to PNM's Annual Report 1-6986 Facility Lease dated as of August 12, 1986, between on Form 10-K for fiscal year The First National Bank of Boston, as Owner Trustee, ended December 31, 1987. and Public Service Company of New Mexico. (Unit 2 Transaction.) (This is an amendment to a Facility Lease which is substantially similar to the Facility Lease filed as Exhibit 28.1 to the Company's Current Report on Form 8-K dated August 18, 1986.) 10.32** Supplemental Employee Retirement Agreements dated 10.32 to PNM's Annual Report 1-6986 August 4, 1989, Between Public Service Company of on Form 10-K for fiscal year New Mexico and John R. Ackerman and Max Maerki ended December 31, 1999. (refilled). 10.32.1** First Amendment to the Supplemental Employee 10.32.1 to PNM's Quarterly 1-6986 Retirement Agreement for Max H. Maerki, as amended Report on Form 10-Q for the effective August 10, 1998. quarter ended September 30, 1998. 10.32.2** Second Amendment to the Supplemental Employee 10.32.2 to PNM's Quarterly 1-6986 Retirement Agreement for Max H. Maerki, as Report on Form 10-Q for the amended effective December 7, 1998 quarter ended March 31, 1999.
E-11
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.32.3** First Amendment to the Supplemental Employee 10.32.3 to PNM's Quarterly 1-6986 Retirement Agreement for John T. Ackerman, as Report on Form 10-Q for the amended effective December 7, 1998 quarter ended March 31, 1999. 10.34 Settlement Agreement between Public Service Company 10.34 to PNM's Quarterly 1-6986 of New Mexico and Creditors of Meadows Resources, Report on Form 10-Q for Inc. dated November 2, 1989 (refiled). quarter ended June 30, 2000. 10.34.1 First amendment dated April 24, 1992 to the 10.34.1 to PNM's Quarterly 1-6986 Settlement Agreement dated November 2, 1989 Report on Form 10-Q among Public Service Company of New quarter ended June 30, 2000. Mexico, the lender parties thereto and collateral agent (refiled). 10.35 Amendment dated April 11, 1991 among Public Service 19.1 to PNM's Quarterly 1-6986 Company of New Mexico, certain banks and Chemical Report on Form 10-Q for the Bank and Citibank, N.A., as agents for the banks. quarter ended September 30, 1991. 10.36 San Juan Unit 4 Purchase and Participation Agreement 19.2 to PNM's Quarterly 1-6986 Public Service Company of New Mexico and the City of Report on Form 10-Q for the Anaheim, California dated April 26, 1991. quarter ended March 31, 1991. 10.36.1 Amendment No. 1 to the San Juan Unit 4 Purchase and 10.36.1 to Annual Report 1-6986 Participation Agreement between Public Service PNM's on Form 10-K for fiscal Company of New Mexico and The City of Anaheim, year ended California, dated October 27, 1999 December 31, 1999. 10.38 Restated and Amended San Juan Unit 4 Purchase and 10.2.1 to PNM's Quarterly 1-6986 Participation Agreement between Public Service Report on Form 10-Q for the Company of New Mexico and Utah Associated Municipal quarter ended September 30, Power Systems. 1993. 10.38.1 Amendment No. 1 to the Restated and Amended San Juan 10.38.1 to PNM's Annual 1-6986 Unit 4 Purchase And Participation Agreement between Report on Form 10-K for Public Service Company of New Mexico And Utah fiscal year ended December Associated Municipal Power Systems, dated October 31, 1999. 27, 1999.
E-12
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.40** PNM Resources, Inc. Director Retainer Plan, dated 4.3 to PNM Resources, Inc. 333-03289 December 31, 2001 Post-Effective Amendment No. 1 to Form 8 Registration Statement filed December 31, 2001 10.41 Waste Disposal Agreement, dated as of July 27, 1992 19.5 to PNM's Quarterly 1-6986 among San Juan Coal Company, PNM and Tucson Electric Report on Form 10-Q for the Power Company. quarter ended September 30, 1992 (confidentiality treatment was requested as to portions of this exhibit, and such portions were omitted from the exhibit filed and were filed separately with the Securities and Exchange Commission). 10.42 Stipulation in the matter of the application of Gas 10.42 to PNM's Annual Report 1-6986 Company of New Mexico for an order authorizing on Form 10-K for fiscal year recovery of MDL costs through Rate Rider Number 8. ended December 31, 1992. 10.43 2001 Officer Incentive Plan effective January 1, 2001 10.43 to PNM's Annual Report on Form 10-K for the fiscal year ended December 31, 2000 10.44.2** Second Restated and Amended Non-Union Severance 10.44.2 to PNM's Quarterly 1-6986 Pay Plan of Public Service Company of New Report on Form 10-Q for Mexico dated the August 1, 1999 quarter ended September 30, 1999. 10.45** Second Amendment to the Public Service Company 10.45 to PNM's Quarterly 1-6986 of New Mexico Service Bonus Plan, as amended Report on Form 10-Q effective December 7, 1998. for the quarter ended March 31, 1999. 10.47** Compensation Arrangement with Chief Executive 10.3 to PNM's Quarterly 1-6986 Officer, Benjamin F. Montoya effective June 23, 1993. Report on Form 10-Q for the quarter ended June 30, 1993.
E-13
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.47.1** Pension Service Adjustment Agreement for Benjamin F. 10.3.1 to PNM's Quarterly 1-6986 Montoya. Report on Form 10-Q for the quarter ended September 30, 1993. 10.47.2** Severance Agreement for Benjamin F. Montoya. 10.3.2 to PNM's Quarterly 1-6986 Report on Form 10-Q for the quarter ended September 30, 1993. 10.47.4** First Amendment to the Pension Service Adjustment 10.47.4 to PNM's Quarterly 1-6986 Agreement for Benjamin F. Montoya. Report on Form 10-Q for the quarter ended June 30, 1998. 10.47.6** Second Amendment to the Pension Service Adjustment 10.47.6 to PNM's Quarterly 1-6986 Agreement for Benjamin F. Montoya, as amended Report on Form 10-Q for the effective December 7, 1998 quarter ended March 31, 1999. 10.48** Public Service Company of New Mexico OBRA `93 10.4 to PNM's Quarterly 1-6986 Retirement Plan. Report on Form 10-Q for the quarter ended September 30, 1993. 10.48.1** First Amendment to the Public Service Company 10.48.1 to PNM's Quarterly 1-6986 of New Mexico OBRA '93 Retirement Plan, as Report on Form 10-Q for the amended effective December 7, 1998 quarter ended March 31, 1999. 10.49** Employment Contract By and Between Public Service 10.49 to PNM's Annual Report 1-6986 Company of New Mexico and Roger J. Flynn. on Form 10-K for fiscal year ended December 31, 1994. 10.50** Public Service Company of New Mexico Section 415 Plan 10.50 to PNM's Annual Report 1-6986 dated January 1, 1994. on Form 10-K for fiscal year ended December 31, 1993.
E-14
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.51.2** First Restated and Amended Executive Retention Plan, 10.51.2 to PNM's Quarterly 1-6986 as amended effective December 7, 1998 Report on Form 10-Q for the quarter ended March 31, 1999. 10.53 January 12, 1994 Stipulation. 10.53 to PNM's Annual Report 1-6986 on Form 10-K for fiscal year ended December 31, 1993. 10.54.1** Health Care and Retirement Benefit Agreement By and 10.54.1 to PNM's Quarterly 1-6986 Between the Public Service Company of New Mexico and Report on Form 10-Q for the John T. Ackerman dated February 1, 1994. quarter ended March 31, 1994. 10.56.1 Amended and Restated Receivables Purchase Agreement 10.56.1 to PNM's Quarterly 1-6986 dated May 20, 1996, between Public Service Company of Report on Form 10-Q for the New Mexico, Citibank and Citicorp North America, Inc. quarter ended June 30, 1996. and Amended Restated Collection Agent Agreement dated May 20, 1996, between Public Service Company of New Mexico, Corporate Receivables Corporation and Citibank, N.A. 10.59* Amended and Restated Lease dated as of September 1, 10.59 to PNM's Annual 1-6986 1993, between The First National Bank of Boston, Report on Form 10-K for Lessor, and PNM, Lessee (EIP Lease). fiscal year ended December 31, 1993. 10.61 Participation Agreement dated as of June 30, 1983 10.61 to PNM's Annual 1-6986 among Security Trust Company, as Trustee, Report on Form 10-K for PNM, Tucson Electric Power Company and certain fiscal year ended December financial institutions relating to the 31, 1993. San Juan Coal Trust (refiled). 10.62 Agreement of PNM pursuant to Item 601(b)(4)(iii) of 10.62 to PNM's Annual 1-6986 Regulation S-K (refiled). Report on Form 10-K for fiscal year ended December 31, 1993. 10.64** Results Pay 10.64 to PNM's Quarterly 1-6986 Report on Form 10-Q for the quarter ended March 31, 1995.
E-15
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.65 Agreement for Contract Operation and Maintenance of the 10.64 to PNM's Quarterly 1-6986 City of Santa Fe Water Supply Utility System, dated Report on Form 10-Q for the July 3, 1995. quarter ended June 30, 1995. 10.67 New Mexico Public Service Commission Order dated July 10.67 to PNM's Annual 1-6986 30, 1987, and Exhibit I thereto, in NMPUC Case No. Report on Form 10-K for 2004, regarding the PVNGS decommissioning trust fund fiscal year ended December (refiled). 31, 1997. 10.68 Master Decommissioning Trust Agreement for Palo Verde 10.68 to PNM's Quarterly 1-6986 Nuclear Generating Station dated March 15, 1996, Report on Form 10-Q for the between Public Service Company of New Mexico and quarter ended March 31, 1996. Mellon Bank, N.A. 10.68.1 Amendment Number One to the Master Decommissioning 10.68.1 to PNM's Annual 1-6986 Trust Agreement for Palo Verde Nuclear Generating Report of the Registrant on Station dated January 27, 1997, between Public Service Form 10-K for fiscal year Company of New Mexico and Mellon Bank, N.A. ended December 31, 1997. 10.69* Refunding Agreement No. 3 dated as of September 27, 10.69 to PNM's Quarterly 1-6986 1996 between Public Service Company of New Mexico, Report on Form10-Q for the The Owner Participant named therein, quarter ended September 30, State Street Bank and Trust Company, as 1996. Owner Trustee, The Chase Manhattan, Bank, as Indenture Trustee, and First PV Funding Corporation. 10.72 Revolving Credit Agreement dated as of March 11, 10.72 to PNM's Quarterly 1-6986 1998, among PNM, the Chase Manhattan Bank, Report on Form 10-Q for the Citibank, N.A., Morgan Guaranty quarter ended March 31, Trust Company of New York, and Chase 1998. Securities, Inc., and the Initial Lenders Named Therein. 10.73 Refunding Agreement No. 8A, dated as 10.73 to PNM's Quarterly 1-6986 of December 23, 1997, among PNM, the Owner Report on Form 10-Q for the Participant Named Therein, State Street quarter ended March 31, Bank and Trust Company, as Owner 1998. Trustee, The Chase Manhattan Bank, as Indenture Trustee, nd First PV a Funding Corporation.
E-16
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.74** Third Restated and Amended Public 10.74 to PNM's Quarterly 1-6986 Service Company of New Mexico Report on Form 10-Q for the Performance Stock Plan effective March 10, 1998. quarter ended March 31, 1998. 10.74.1** First Amendment to the Third Restated 10.74.1 to PNM's Quarterly 1-6986 and Amended Public Service Company Report on Form 10-Q for the of New Mexico Performance Stock Plan quarter ended March 31, 2000. Dated February 7, 2000 10.74.2** Second Amendment to the Third Restated and Amended 10.74.2 to PNM's Annual Public Service Company of New Mexico Performance Report on Form 10-K for the Stock Plan, effective December 7, 1998 fiscal year ended December 31, 2000 10.74.3** Third Amendment to the Third Restated and Amended 10.74.3 to PNM's Annual Public Service Company of New Mexico Performance Report on Form 10-K for the Stock Plan, effective December 10, 2000 fiscal year ended December 31, 2000 10.74.4** Fourth Amendment to Third Restated and Amended Public 4.3.5 to PNM Resources' 333-03303 Service Company of New Mexico Performance Stock Plan Post-Effective Amendment dated December 31, 2001 No. 1 to Form 8 Registration Statement filed December 31, 2001 10.75** First Amended and Restated Public Service Company of 10.75 to PNM Resources and 1-6986 New Mexico Executive Savings Plan dated November 16, PNM's Annual Report on Form 2001. 10-K for the fiscal year ended December 31, 2001 10.75.1** First Amendment to the First Amended and Restated 4.6 to PNM Resources' Form 333-76316 Public Service Company of New Mexico Executive 8 Registration Statement Savings Plan effective January 1, 2002 filed January 4, 2002
E-17
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.76 PVNGS Capital Trust--Variable Rate 10.76 to PNM's Quarterly 1-6986 Trust Notes--PVNGS Note Agreement Report on Form 10-Q for the dated as of July 31, 1998. quarter ended September 30, 1998. 10.77 San Juan Project Participation Agreement dated as of 10.77 to PNM's Quarterly 1-6986 October 27, 1999, among Public Service Company of New Report on Form 10-Q for the Mexico, Tucson Electric Power Company, The City of quarter ended September 30, Farmington, New Mexico, M-S-R Public Power Agency, 1999. The Incorporated County of Los Alamos, New Mexico, Southern California Public Power Authority, City of Anaheim, Utah Associated Municipal Power System and Tri-State Generation and Transmission Association, Inc. 10.78 Stipulation in the matter of the Commission's 10.78 to PNM's Quarterly 1-6986 investigation of the rates for electric service of Report on Form 10-Q for the Public Service Company of New Mexico, Rate Case No. quarter ended September 30, 2761, dated May 21, 1999 1999. 10.78.1 Stipulation in the matter of the Commission's 10.78.1 to PNM's Quarterly 1-6986 investigation of the rates for electric service of Report on Form 10-Q for the Public Service Company of New Mexico, Rate Case No. quarter ended September 30, 2761, dated May 27, 1999 1999. 10.79 Asset Sale Agreement between Tri-State Generation and 10.79 to PNM's Quarterly 1-6986 Transmission Association, Inc., a Colorado Report on Form 10-Q for the Cooperative Association and Public Service Company of quarter ended September 30, New Mexico, a New Mexico Corporation, dated September 1999. 9, 1999 10.80** Supplemental Employee Retirement 10.80 to PNM's Quarterly 1-6986 Agreement, dated March 14, 2000 for Report on Form 10-Q for the Patrick T. Ortiz quarter ended March 31, 2000.
E-18
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.81** Supplemental Employee Retirement 10.81 to PNM's Quarterly 1-6986 Agreement, dated March 22, 2000 for Report on Form 10-Q for the Jeffry E. Sterba quarter ended March 31, 2000. 10.82 PNM Resources, Inc. Omnibus Performance Equity 4.3 to PNM Resources' Form 333-76288 Plan dated December 31, 2001 8 Registration Statement filed January 4, 2001 10.83 Transportation Agreement Buy Out Agreement, dated 10.83 to PNM's Quarterly August 31, 2001 among San Juan Transportation Report on Form 10-Q for the Company, PNM and Tucson Electric Power Company. quarter ending September 31, 2001 (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 10.8 4 to PNM's Quarterly 31, 2001 among San Juan Coal Company, PNM and Tucson Report on Form 10-Q for the Electric Power Company. quarter ending September 31, 2001 (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.)
E-19
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 10.85 Underground Coal Sales Agreement, dated August 31, 10.85 to PNM's Quarterly 2001 among San Juan Coal Company, PNM and Tucson Report on Form 10-Q for the Electric Power Company. quarter ending September 31, 2001 (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.) Additional Exhibits 99.2* Participation Agreement dated as of 99.2 to PNM's Annual Report 1-6986 December 16, 1985, among the Owner on Form 10-K for fiscal Participant named therein, First PV year ended December 31, Funding Corporation. The First National 1995. Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of December 16, 1985 with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 16, 1985 with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions together with Amendment No. 1 dated July 15, 1986 and Amendment No. 2 dated November 18, 1986 refiled). 99.3 Trust Indenture, Mortgage, Security 99.3 to PNM's Quarterly 1-6986 Agreement and Assignment of Rents Report on Form 10-Q for the dated as of December 16, 1985, between quarter ended March 31, the First National Bank of Boston, as 1996. Owner Trustee, and Chemical Bank, as Indenture Trustee together with Supplemental Indentures Nos. 1 and 2 (refiled).
E-20
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 99.3.3 Supplemental Indenture No. 3 dated as 99.3.3 to PNM's Quarterly 1-6986 of March 8, 1995, to Trust Indenture Report on Form 10-Q for the Mortgage, Security Agreement and quarter ended March 31, Assignment of Rents between The First 1995. National Bank of Boston and Chemical Bank dated as of December 16, 1985. 99.4* Assignment, Assumption and Further 99.4 to PNM's Annual Report 1-6986 Agreement dated as of December 16, 1985, on Form 10-K for fiscal between Public Service Company of New year ended December 31, 1995. Mexico and The First National Bank of Boston, as Owner Trustee (refiled). 99.5 Participation Agreement dated as of July 99.5 to PNM's Annual Report 1-6986 31, 1986, among the Owner Participant on Form 10-K for fiscal named herein, First PV Funding year ended December 31, Corporation, The First National Bank of 1996. Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of July 31, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of July 31, 1986, with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions together with Amendment No. 1 thereto (refiled). 99.6 Trust Indenture, Mortgage, Security 99.6 to PNM's Annual Report 1-6986 Agreement and Assignment of Rents on Form 10-K for fiscal dated as of July 31, 1986, between ended December 31, 1996. The First National Bank of Boston, as Owner Trustee, and Chemical Bank, as Indenture Trustee together with Supplemental Indenture No. 1 thereto (refiled). 99.7 Assignment, Assumption, and Further 99.7 to PNM's Annual Report 1-6986 Agreement dated as of July 31, 1986, on Form 10-K for fiscal between Public Service Company of year ended December 31, New Mexico and The First National Bank 1996. of Boston, as Owner Trustee (refiled).
E-21
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 99.8 Participation Agreement dated as of 99.8 to PNM's Quarterly 1-6986 August 12, 1986, among the Owner Report on Form 10-Q for the Participant named therein, First PV quarter ended March 31, Funding Corporation. The First National 1997. Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of August 12, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of August 12, 1986, with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions (refiled). 99.8.1* Amendment No. 1 dated as of November 99.8.1 to PNM's Quarterly 1-6986 18, 1986, to Participation Agreement Report on Form 10-Q for the dated as of August 12, 1986 (refiled). quarter ended March 31, 1997. 99.9* Trust Indenture, Mortgage, Security 99.9 to PNM's Annual Report 1-6986 Agreement and Assignment of Rents of the Registrant on Form dated as of August 12, 1986, between the 10-K for fiscal year ended First National Bank of Boston, as Owner December 31, 1996. Trustee, and Chemical Bank, as Indenture Trustee together with Supplemental Indenture No. 1 thereto (refiled). 99.9.2 Supplemental Indenture No. 2 dated as 99.9.1 to PNM's Quarterly 1-6986 of March 8, 1995, to Trust Indenture, Report on Form 10-Q for the Mortgage, Security Agreement and quarter ended March 31, Assignment of Rents between The First 1995. National Bank of Boston and Chemical Bank dated as of August 12, 1986. 99.10* Assignment, Assumption, and Further 99.10 to PNM's Quarterly 1-6986 Agreement dated as of August 12, 1986, Report on Form 10-Q for the between Public Service Company of New quarter ended March 31, 1997. Mexico and The First National Bank of Boston, as Owner Trustee (refiled).
E-22
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 99.11* Participation Agreement dated as of December 99.1 to PNM's Quarterly 1-6986 15, 1986, among the Owner Participant named Report on Form 10-Q for the therein, First PV Funding Corporation, The First quarter ended March 31, 1997. National Bank of Boston, in its individual capacity and as Owner Trustee (under a Trust Agreement dated as of December 15, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 15, 1986, with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions (Unit 1 Transaction) (refiled). 99.12 Trust Indenture, Mortgage, Security 99.12 to PNM's Quarterly 1-6986 Agreement and Assignment of Rents Report on Form 10-Q for the dated as of December 15, 1986, between quarter ended March 31, The First National Bank of Boston, as 1997. Owner Trustee, and Chemical Bank, as Indenture Trustee (Unit 1 Transaction) (refiled). 99.13 Assignment, Assumption and Further 99.13 to PNM's 1-6986 Agreement dated as of December 15, Quarterly Report on Form 1986, between Public Service Company 10-Q for the quarter ended of New Mexico and The First National March 31, 1997. Bank of Boston, as Owner Trustee (Unit 1 Transaction) (refiled). 99.14 Participation Agreement dated as of December 99.14 to PNM's 1-6986 15, 1986, among the Owner Participant named Quarterly Report on Form therein, First PV Funding Corporation, The First 10-Q for the quarter ended National Bank of Boston, in its individual March 31, 1997. capacity and as Owner Trustee (under a Trust Agreement dated as of December 15, 1986, with the Owner Participant), Chemical Bank, in its individual capacity and as Indenture Trustee (under a Trust Indenture, Mortgage, Security Agreement and Assignment of Rents dated as of December 15, 1986, with the Owner Trustee), and Public Service Company of New Mexico, including Appendix A definitions (Unit 2 Transaction) (refiled).
E-23
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 99.15 Trust Indenture, Mortgage, Security 99.15 to PNM's Annual 1-6986 Agreement and Assignment of Rents dated Report on Form 10-K for as of December 31, 1986, between the fiscal year ended December First National Bank of Boston, as Owner 31, 1996. Trustee, and Chemical Bank, as Indenture Trustee (Unit 2 Transaction) (refiled). 99.16 Assignment, Assumption, and Further 99.16 to PNM's Quarterly 1-6986 Agreement dated as of December 15, Report on Form 10-Q for the 1986, between Public Service Company of quarter ended March 31, 1997. New Mexico and The First National Bank of Boston, as Owner Trustee (Unit 2 Transaction) (refiled). 99.17* Waiver letter with respect to "Deemed 99.17 to PNM's Annual 1-6986 Loss Event" dated as of August 18, 1986, Report on Form 10-K for between the Owner Participant named fiscal year ended December therein, and Public Service Company of 31, 1996. New Mexico (refiled). 99.18* Waiver letter with respect to Deemed 99.18 to PNM's Annual 1-6986 Loss Event" dated as of August 18, 1986, Report on Form 10-K for between the Owner Participant named fiscal year ended December therein, and Public Service Company of 31, 1996. New Mexico (refiled). 99.19 Agreement No. 13904 (Option and Purchase of Effluent), 99.19 to PNM's Annual 1-6986 dated April 23, 1973, among Arizona Public Service Report on Form 10-K for Company, Salt River Project Agricultural Improvement fiscal year ended December and Power District, the Cities of Phoenix, Glendale, 31, 1996. Mesa, Scottsdale, and Tempe, and the Town of Youngtown (refiled). 99.20 Agreement for the Sale and Purchase of 99.20 to PNM's Annual 1-6986 Wastewater Effluent, dated June 12, 1981, Report on Form 10-K for Among Arizona Public Service Company, fiscal year ended December Salt River Project Agricultural 31, 1996. Improvement and Power District and the City of Tolleson, as amended (refiled). 99.21* 1996 Supplemental Indenture dated as of 99.21 to PNM's Quarterly 1-6986 September 27, 1996 to Trust Indenture, Report on Form 10-Q for the Mortgage, Security Agreement and quarter ended September 30, Assignment of Rents dated as of December 1996. 16, 1985 between State Street Bank and Trust Company, as Owner Trustee, and The Chase Manhattan Bank, as Indenture Trustee.
E-24
Exhibit No. Description of Exhibit Filed as Exhibit: File No: - ----------- ---------------------- ----------------- -------- 99.22 1997 Supplemental Indenture, dated as of 99.22 to PNM's Quarterly 1-6986 December 23, 1997, to Trust Indenture, Report on Form 10-Q for the Mortgage, Security Agreement and quarter ended March 30, Assignment of Rents, dated as of August 1998. 12, 1986, between State Street Bank and Trust, as Owner Trustee, and The Chase Manhattan Bank, as Indenture Trustee.
- ----------- * One or more additional documents, substantially identical in all material respects to this exhibit, have been entered into, relating to one or more additional sale and leaseback transactions. Although such additional documents may differ in other respects (such as dollar amounts and percentages), there are no material details in which such additional documents differ from this exhibit. ** Designates each management contract or compensatory plan or arrangement required to be identified pursuant to paragraph 3 of Item 14(a) of Form 10 -K. E-25 (b) Reports on Form 8-K: During the quarter ended December 31, 2001 and during the period beginning January 1, 2002 and ending March 22, 2002, the Company filed, on the date indicated, the following reports on Form 8-K.
Dated: Filed: Relating to: ------ ------ ------------ September 30, 2001 October 11, 2001 The Company Reports Comparative Operating Statistics for September 2000 and 2001 October 12, 2001 October 16, 2001 The Company Reports Court to Rule on Western Resources Agreement October 23, 2001 October 23, 2001 The Company Reports Third Quarter 2001 Earnings Conference Call October 24, 2001 October 25, 2001 The Company Reports Quarter and Nine Months Ended September 30, 2001 Earnings Announcement and Consolidated Statement of Earnings October 30, 2001 November 2, 2001 The Company Reports Merchant Utility Model Combines Growth with Stability, CEO Tells Analysts October 31, 2001 November 15, 2001 The Company Reports Comparative Operating Statistics for October 2000 and 2001 November 15, 2001 November 16, 2001 The Company Reports Breaking Ground on New Generating Plant in Southern NM November 19, 2001 November 30, 2001 The Company Reports Certain Pending Litigation Brought by the Company in New York State Court Against Western Resources November 30, 2001 December 12, 2001 The Company Reports Comparative Operating Statistics for November 2000 and 2001 December 11, 2001 December 14, 2001 The Company Reports University President is Named to the Company's Board of Directors December 11, 2001 December 14, 2001 The Company Declares Common and Preferred Stock Dividend December 19, 2001 December 20, 2001 The Company Reports an Approved Settlement between the Company and Other Parties to Allow Activation of a New Holding Company
E-26
Dated: Filed: Relating to: ------ ------ ------------ December 20, 2001 December 27, 2001 The Company Reports Asking a New York Court to Dismiss a Lawsuit Filed Against the Company by Western Resources December 31, 2001 December 31, 2001 The Company Reports Shareholders of the Company Approved Management's Plan to Create a New Holding Company January 8, 2002 January 9, 2002 The Company Reports Terminating the Western Resources Agreement January 9, 2002 January 10, 2002 The Company Announces New Power Plant in Southern New Mexico December 31, 2001 January 15, 2002 The Company Reports Comparative Operating Statistics for December 2001 and 2000 January 22, 2002 January 23, 2002 The Company Reports Plans to Retire Transmission Line Debt January 23, 2002 January 24, 2002 The Company Reports Quarter and Nine Months Ended December 31, 2001 Earnings Announcement and Consolidated Statement of Earnings February 19, 2002 February 21, 2002 The Company Reports an Increase in Common Stock Dividend January 31, 2002 February 27, 2002 The Company Reports Comparative Operating Statistics for January 2002 and 2001 February 28, 2002 March 14, 2002 The Company Reports Comparative Operating Statistics for February 2002 and 2001 March 19, 2002 March 19, 2002 The Company Reports 2002 Annual Meeting of Shareholders on May 14, 2002
E-27 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PNM RESOURCES, INC. (Registrant) Date: March 26, 2002 By /s/ J. E. Sterba ---------------------------------------- J. E. Sterba Chairman, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. Signature Capacity Date --------- -------- ---- /s/ J. E. STERBA Principal Executive March 26, 2002 - --------------------------------- Officer and Chairman J. E. Sterba of the Board Chairman, President and Chief Executive Officer /s/ M. H. MAERKI Principal Financial March 26, 2002 - --------------------------------- Officer M. H. Maerki Senior Vice President and Chief Financial Officer /s/ J. R. LOYACK Principal Accounting March 26, 2002 - --------------------------------- Officer J. R. Loyack Vice President, Corporate Controller and Chief Accounting Officer /s/ R. G. ARMSTRONG Director March 26, 2002 - --------------------------------- R. G. Armstrong /s/ R. M. CHAVEZ Director March 26, 2002 - --------------------------------- R. M. Chavez /s/ J. A. GODWIN Director March 26, 2002 - --------------------------------- J. A. Godwin /s/ B. F. MONTOYA Director March 26, 2002 - --------------------------------- B. F. Montoya /s/ M. T. PACHECO Director March 26, 2002 - --------------------------------- M. T. Pacheco /s/ T. F. PATLOVICH Director March 26, 2002 - --------------------------------- T. F. Patlovich /s/ R. M. PRICE Director March 26, 2002 - --------------------------------- R. M. Price /s/ P. F. ROTH Director March 26, 2002 - --------------------------------- P. F. Roth E-28 EX-3.(I) 3 exh_31.txt EXHIBIT 3.1 Exhibit 3.1 - ------------------------------------------------------------------------------- RESTATED ARTICLES OF INCORPORATION OF PNM RESOURCES, INC. RESTATED ARTICLES OF INCORPORATION AS FILED FEBRUARY 22, 2002 - ------------------------------------------------------------------------------- RESTATED ARTICLES OF INCORPORATION OF PNM RESOURCES, INC. These Restated Articles of Incorporation are executed in the manner prescribed by the New Mexico Business Corporation Act pursuant to a resolution adopted by the Board of Directors of PNM Resources, Inc. on November 16, 2001. The Restated Articles of Incorporation correctly set forth without change the corresponding provisions of the original Articles of Incorporation of PNM Resources, Inc. (formerly named Manzano Corporation) as filed March 3, 2000, as amended on April 12, 2001 and July 13, 2001, and supercede the original Articles of Incorporation and all previous amendments thereto. ARTICLE I Name ---- The name of the Corporation is PNM Resources, Inc. ARTICLE II Period of Duration ------------------ The period of its duration is perpetual. ARTICLE III Purpose ------- The purposes of the Corporation are to hold the voting securities of other companies and to engage in any other lawful business for which corporations may be incorporated under the laws of the State of New Mexico. The Corporation shall have all the powers that are lawful for a corporation to exercise under New Mexico law. 1 ARTICLE IV Authorized Number of Shares --------------------------- A. Authorized Capital Shares. The total number of shares of stock which the Corporation shall have the authority to issue is One Hundred Thirty (130) Million shares, of which One Hundred Twenty (120) Million shares shall be Common Stock, no par value, and Ten (10) Million shares shall be Preferred Stock, no par value. Common Stock and Preferred Stock shall be issued for such minimum consideration as authorized by the Board of Directors. B. Common Stock. The Board of Directors is authorized by resolution to provide from time to time for the issuance of shares of Common Stock subject to the following restrictions and qualifications: (1) Dividends. Subject to any rights of holders of Preferred Stock, such dividends (payable in cash, stock or otherwise) as may be determined by the Board of Directors may be declared and paid on the Common Stock from time to time from any available funds, property or shares. (2) Voting Rights. Subject to any rights of holders of Preferred Stock to vote on a matter as a class or series, each outstanding share of Common Stock shall be entitled to one vote on each matter submitted to a vote of holders of Common Stock at a meeting of shareholders. Cumulative voting for the election of directors of the Corporation shall not be permitted. (3) Liquidation, Dissolution or Winding Up. In the event of any liquidation, dissolution or winding up of the Corporation, the holders of Common Stock shall be entitled to receive the net balance of any assets of the Corporation remaining after any distribution of the assets of the Corporation to the holders of Preferred Stock to the extent necessary to satisfy any preferences to the assets. 2 C. Preferred Stock. The Board of Directors is authorized by resolution to provide from time to time for the issuance of shares of Preferred Stock in series and to fix, from time to time before issuance, the designation, preferences, privileges and voting powers of the shares of each series of Preferred Stock and its restrictions or qualifications, limited to the following: (1) the serial designation, authorized number of shares and the stated value; (2) the dividend rate, if any, the date or dates on which the dividends will be payable, and the extent to which the dividends may be cumulative; (3) the price or prices at which shares may be redeemed, and any terms, conditions and limitations upon any redemption; (4) the amount or amounts to be received by the holders in the event of dissolution, liquidation, or winding up of the Corporation; (5) any sinking fund provisions for redemption or purchase of shares of any series; (6) the terms and conditions, if any, on which shares may be converted into, or exchanged for, shares of other capital stock, or of other series of Preferred Stock, of the Corporation; and (7) the voting rights, if any, for the shares of each series, limited to circumstances when: (a) the Corporation fails to pay dividends on the applicable series; and (b) when a proposed amendment to these Articles would have an adverse impact on the rights and privileges of the preferred stockholders. 3 D. Preemptive Rights. The holders of Common Stock or Preferred Stock shall not have a preemptive right to acquire authorized but unissued shares, securities convertible into shares or carrying a right to subscribe to or acquire shares, except under such terms and conditions as may be provided by the Board of Directors in its sole judgment. ARTICLE V Stock Rights and Options ------------------------ The Board of Directors in its sole judgment may create and issue rights or options entitling the holders, which may include directors, officers or employees of the Corporation, to purchase from the Corporation shares of any class of stock. ARTICLE VI Directors --------- The number of directors of the Corporation shall be as specified in the Bylaws but shall be no less than five (5) and no more than twelve (12). The number of directors may be increased or decreased from time to time as provided in the Bylaws so long as no decrease shall have the effect of shortening the term of any incumbent director. To the extent and in the manner provided by law, the directors may be classified as to the time for which they severally hold office, in accordance with the Bylaws of the Corporation. The initial Board of Directors shall consist of seven members, and the names and addresses of the persons who are to serve as the initial Directors until the first annual meeting of shareholders, or until their successors shall have been elected and qualified, are: 4 Name Address ---- ------- John T. Ackerman 165 Sol de Oro Court Corrales, NM 87048 Robert G. Armstrong 2608 North Washington Roswell, NM 88201 Joyce A. Godwin 904 Brazos Place SE Albuquerque, NM 87123 Benjamin F. Montoya Alvarado Square, MS 2824 Albuquerque, NM 87158 Theodore F. Patlovich 11109 Bobcat NE Albuquerque, NM 87122 Robert M. Price 14579 Grand Ave. S., Suite 100 Burnsville, MN 55306 Jeffry E. Sterba Alvarado Square, MS 2802 Albuquerque, NM 87158 ARTICLE VII Limitation on Liability ----------------------- The liability of the directors of the Corporation for monetary damages shall be eliminated or limited to the fullest extent permissible under New Mexico law as may be amended from time to time. ARTICLE VIII Address of Initial Registered Office and Name of Initial Registered Agent ------------------------------------------------------------------------- The address of the Corporation's initial registered office is: Alvarado Square, MS 2822, Albuquerque, NM 87158. The name of the Corporation's initial registered agent at that address is Patrick T. Ortiz. 5 ARTICLE IX Incorporator ------------ The name and address of the Incorporator is Public Service Company of New Mexico, Alvarado Square, Albuquerque, New Mexico 87158. Dated February 18, 2002. PNM RESOURCES, INC. By: /s/ Jeffry E. Sterba ------------------------------------- Jeffry E. Sterba, Chairman, President and Chief Executive Officer 6 EX-10 4 exh_1052.txt EXHIBIT 10.52 EXHIBIT 10.52 EXECUTIVE SPENDING ACCOUNT -------------------------- Date: January 16, 2002 To: (by name) From: Don Boulware Subject: CORRECTED Executive Spending Account Procedures Effective January 1, 2002, PNMR initiated an Executive Spending Account (ESA, not to be confused with ESP which is the Executive Savings Plan) for all Officers. Under the ESA, certain expenditures can be reimbursed up to the limit assigned by the Company. Your limit is XXXXXXX per payroll year. The payroll year differs slightly from the calendar year due to the payroll practice of every-other- week paychecks. See the paragraph below titled Paycheck Year. The reimbursements will constitute taxable income to you. Reimbursements will be included in your regular paycheck, and the additional taxable income will be reflected in your W-2 for 2002. Health claims filed for reimbursement can be for you, and any dependent you have enrolled, or could have enrolled, under the PNMR health plans. REIMBURSABLE EXPENSES - --------------------- Reimbursable expenses under the ESA are: 1. Income tax preparation costs; 2. Costs for Estate Planning (including preparation of wills and trusts) and/or Financial Counseling, but excluding brokerage fees or commissions; 3. Insurance Premiums covering you and your dependents for Health (medical, dental, vision, etc.), Accident, Disability, Life, Dependent Life, Long Term Care and/or Supplemental Insurance (similar to AFLAIC), whether paid from your pocket as private insurance or deducted from your salary under a PNM benefit program; 4. Insurance premiums for home, auto or personal liability umbrella; 5. Health (medical, dental, vision and/or prescription drug) costs for you and your dependents that are not covered by either your regular PNM insurance or your Medical Expense Reimbursement Plan (MERP), or which are in excess of your MERP limit of $3,000. For these health costs to be eligible for reimbursement, you must FIRST file the claim through your regular PNM health insurance carrier, and SECOND through your MERP. Any costs remaining unpaid, after filing your claim under the regular PNM insurance and MERP, can be filed under this ESA. HOWEVER, AS WITH THE PNM INSURANCE AND MERP, THE CLAIM MUST STILL BE FOR A SERVICE OR DRUG THAT IS A COVERED EXPENSE UNDER IRS CODE 213(d). Covered expenses under IRS code 213(d) are outlined under the separately enclosed document entitled "Medical Expense Reimbursement Plan." NOTE: The reimbursement of the cost of personal insurance premiums does not constitute an endorsement by PNMR of your choice of insurance carriers. The choice of insurance carriers for personal lines of insurance is entirely up to you. To receive reimbursement under this ESA, submit an ESA claim form (attached), and documentation in the form of invoices or receipts, to Don Boulware, MS-3101. As this program deals with information usually considered highly confidential, the Manager, Benefits, and not subordinate staff, will administer the ESA. Confidentiality is guaranteed. Cancelled checks cannot be used as the sole documentation of an expense submitted for reimbursement. Because this ESA plan is not tax-advantaged, the reimbursement is considered taxable income for the year the reimbursement is made, not the year in which the claim was incurred. Keep in mind that the MERP is just the opposite: in the MERP, the claim-incurred date is the controlling factor. If you do not submit claims up to your allowed annual ESA maximum, the unused portion cannot be carried over to, and aggregated with, the maximum for the following year. PAYCHECK YEAR - ------------- For 2002, the last paycheck allocated to 2002 earnings, and which will be included in your W-2 for the year 2002, will be issued on Friday, December 27. This final paycheck will represent the work weeks ending December 13 and December 20. Your reimbursement requests must be processed and submitted to Accounts Payable, and Accounts Payable must authorize Payroll to include the reimbursement in your final check for 2002. To do this, Accounts Payable must receive the information from Benefits no later than December 6th. Therefore, the initial year for the ESA will stop on December 6, 2002, and the 2003 ESA paycheck year will start on December 7th, 2002. Again, the controlling factor, since the reimbursable expenses are taxable, is the paycheck year that the reimbursement is paid, not the year in which the claim is incurred. 2 SUGGESTED PROCEDURES - -------------------- Some suggested procedures are listed below. o For repetitive expenses, you may wish to submit when you have other, non-repetitive expenses, or at some time interval such as every three or six months. o Benefits Department will calculate the applicable insurance deductions taken from your pay each December, and will automatically submit these for reimbursement, unless you request that the deductions be calculated by the Benefits Department on a more frequent basis. o Be sure the name of the provider, the nature of the service rendered, and your name are on the receipt or invoice. If the claim is in the category of health (other than for prescription drugs), the ICD-9 code assigned by the provider will suffice in place of the nature of service rendered. o To facilitate record keeping and reimbursement, expenses received during a month will be processed for reimbursement during the first week of the following month, except December. In December, we will process on a weekly basis in order to get as much into the taxable paycheck year as is possible. The above procedures are suggested only, in an attempt to streamline the reimbursement process to the greatest extent possible. If you wish to modify the above procedures to address your personal issues or concerns, we can oblige, but we must also be made aware of how you wish us to modify the procedure for your individual case. 3 EX-10 5 exh_1075.txt EXHIBIT 10.75 EXHIBIT 10.75 FIRST RESTATED AND AMENDED PUBLIC SERVICE COMPANY OF NEW MEXICO EXECUTIVE SAVINGS PLAN TABLE OF CONTENTS ARTICLE I DEFINITIONS........................................1 1.1. "Administration Committee" or "Committee"..................1 1.2. "Benefits Department"......................................1 1.3. "Board"....................................................1 1.4. "Code".....................................................1 1.5. "Company"..................................................1 1.6. "Company Stock"............................................1 1.7. "Company Stock Fund".......................................1 1.8. "Compensation".............................................1 1.9. "Investment Fund"..........................................2 1.10. "MESP".....................................................2 1.11. "MESP Employer Contribution"...............................2 1.12. "MESP Employer Contribution Account".......................2 1.13. "MESP Matching Contribution"...............................2 1.14. "Participant"..............................................2 1.15. "Plan".....................................................2 1.16. "Plan Administrator".......................................2 1.17. "Plan Year"................................................2 1.18. "Recordkeeper".............................................2 1.19. "Supplemental Deferral Account"............................2 1.20. "Supplemental Deferral Agreement"..........................2 1.21. "Supplemental Deferrals"...................................2 1.22. "Supplemental Employer Account"............................3 1.23. "Supplemental Employer Credits"............................3 1.24. "Supplemental Matching Credits"............................3 1.25. "Valuation Date"...........................................3 ARTICLE II ELIGIBILITY; ADOPTION BY AFFILIATES................3 2.1. The Eligible Class.........................................3 2.2. Participants...............................................3 2.3. Adoption by Affiliates.....................................3 ARTICLE III SUPPLEMENTAL DEFERRALS AND CREDITS.................3 3.1. Supplemental Deferral Agreement............................3 3.2. Supplemental Deferrals.....................................4 3.3. Supplemental Matching and Employer Credits.................4 3.4. Benefits Not Contingent....................................5 ARTICLE IV INVESTMENT OF ACCOUNTS.............................5 4.1. Adjustment of Accounts.....................................5 4.2. Investment Direction.......................................5 4.3. Special Company Stock Fund Provisions......................6 4.4. Compliance with Securities Laws............................6 -i- TABLE OF CONTENTS (continued) ARTICLE V DISTRIBUTIONS......................................7 5.1. Right to Receive Distribution..............................7 5.2. Form of Distribution.......................................7 5.3. Amount of Distribution.....................................7 5.4. Limits on Distributions of Company Stock...................7 5.5. Timing of Distribution.....................................8 5.6. Beneficiary Designation....................................8 5.7. Withholding................................................8 5.8. Deductibility..............................................8 ARTICLE VI ADMINISTRATION OF THE PLAN.........................8 6.1. Appointment of Committee...................................8 6.2. Majority Rule and Delegation of Ministerial Acts...........8 6.3. Meetings...................................................8 6.4. General Powers and Duties..................................9 6.5. Claims....................................................10 6.6. Appeals...................................................10 ARTICLE VII AMENDMENT OR TERMINATION..........................11 7.1. Amendment or Termination..................................11 7.2. Effect of Amendment or Termination........................11 ARTICLE VIII GENERAL PROVISIONS................................11 8.1. Participant's Rights Unsecured............................11 8.2. No Guaranty of Benefits...................................11 8.3. No Enlargement of Employee Rights.........................11 8.4. Spendthrift Provision.....................................11 8.5. Applicable Law............................................12 8.6. Incapacity of Recipient...................................12 8.7. Successors................................................12 8.8. Unclaimed Benefit.........................................12 8.9. Limitations on Liability..................................12 8.10. Headings for Convenience Only.............................13 8.11. Severability..............................................13 8.12. Conflicts.................................................13 -ii- FIRST RESTATED AND AMENDED PUBLIC SERVICE COMPANY OF NEW MEXICO EXECUTIVE SAVINGS PLAN The PUBLIC SERVICE COMPANY OF NEW MEXICO EXECUTIVE SAVINGS PLAN (the "Plan") was originally effective as of July 1, 1998. The Plan was established by the Public Service Company of New Mexico (the "Company" or "PNM") solely for the purpose of permitting certain of its key employees who participate in the Public Service Company of New Mexico Master Employee Savings Plan (the "MESP") to make and receive credits under this Plan in excess of the limitations on contributions imposed by the Internal Revenue Code of 1986, as amended, or the MESP. By this document, the Company amends and restates the Plan in its entirety, effective as of November 16, 2001. ARTICLE I DEFINITIONS When a word or phrase appears in this Plan with the initial letter capitalized, and the word or phrase does not begin a sentence, the word or phrase shall generally be a term defined in this Article I. The following words and phrases used in the Plan with the initial letter capitalized shall have the meanings set forth in this Article I, unless a clearly different meaning is required by the context in which the word or phrase is used: 1.1. "Administration Committee" or "Committee" means the committee appointed pursuant to Section 6.1 to assume certain designated responsibilities in connection with the Plan. 1.2. "Benefits Department" means the organizational unit of the Company with responsibility for administering benefit programs. 1.3. "Board" means the Board of Directors of the Company, or any authorized committee of the Board. 1.4. "Code" means the Internal Revenue Code of 1986, as amended from time to time, and any regulations promulgated thereunder. 1.5. "Company" means the Public Service Company of New Mexico, and to the extent provided in Section 8.7 below, any successor corporation or other entity resulting from merger or consolidation into or with the Company or a transfer or sale of substantially all of the assets of the Company. 1.6. "Company Stock" means common stock issued by the Company. 1.7. "Company Stock Fund" means the Investment Fund described in Section 4.3. 1.8. "Compensation," for purposes of determining the Supplemental Matching and Employer Credits, means the Participant's base salary and other elements of compensation that are considered under the MESP (as it may be amended from time to time) for purposes of calculating the Participant's MESP Employer and Matching Contributions, respectively. For purposes of determining the amount of a Participant's permissible Supplemental Deferrals, "Compensation" means the Participant's base salary and other elements of compensation that are considered under the MESP (as it may be amended from time to time) for purposes of calculating the Participant's MESP pre-tax contributions. -1- 1.9. "Investment Fund" means the hypothetical investment fund or funds established by the Plan Administrator pursuant to Article IV. 1.10. "MESP" means the Public Service Company of New Mexico Master Employee Savings Plan established effective January 1, 1975, as it may be amended from time to time. 1.11. "MESP Employer Contribution" means the Employer (Nonelective) Contributions made by the Company for the benefit of a Participant under and in accordance with the terms of the MESP in any Plan Year. 1.12. "MESP Employer Contribution Account" means the Matching Contributions Account and/or the Employer Contributions Account established for a Participant under the MESP. 1.13. "MESP Matching Contribution" means the Matching Contributions made by the Company for the benefit of a Participant under and in accordance with the terms of the MESP in any Plan Year. 1.14. "Participant" means an employee of the Company or any affiliate who has been designated or selected for participation in the Plan pursuant to Section 2.2 and to whom or with respect to whom amounts may be credited under the Plan. 1.15. "Plan" means the Public Service Company of New Mexico Executive Savings Plan, as restated and amended, and as set forth in this document. 1.16. "Plan Administrator" means the Company. Any action to be taken by the Plan Administrator may be taken by the Company's senior human resources officer. 1.17. "Plan Year" means the calendar year. 1.18. "Recordkeeper" means the entity selected by the Company to keep Plan records and to adjust accounts pursuant to Section 4.1 of the Plan. 1.19. "Supplemental Deferral Account" means the account maintained under the Plan to record amounts deferred under Section 3.2 of the Plan. 1.20. "Supplemental Deferral Agreement" means the written deferral agreement described in Section 3.1 that is entered into by a Participant with the Company pursuant to this Plan. 1.21. "Supplemental Deferrals" means the deferrals made by a Participant in accordance with Section 3.2. -2- 1.22. "Supplemental Employer Account" means the account maintained under the Plan to record the amounts credited to a Participant in accordance with Section 3.3. 1.23. "Supplemental Employer Credits" means the Employer Credits allocated to a Participant's Supplemental Employer Account in accordance with Section 3.3. 1.24. "Supplemental Matching Credits" means the Matching Credits allocated to a Participant's Supplemental Employer Account in accordance with Section 3.3. 1.25. "Valuation Date" shall mean each business day of the Plan Year. ARTICLE II ELIGIBILITY; ADOPTION BY AFFILIATES 2.1. The Eligible Class. The purpose of the Plan is to provide deferred compensation to a select group of management or highly compensated employees. This group of eligible employees is sometimes referred to as the "top hat group." 2.2. Participants. Any employees of the Company or an adopting affiliate who are Participants in the Plan on the date of adoption of this amended and restated Plan will continue as such for so long as they are members of the top hat group. As noted in Section 2.1, this Plan is intended to provide benefits only to members of the top hat group. The Company has determined that all of the current Participants are properly included in the top hat group. 2.3. Adoption by Affiliates. An employee of an affiliate may not become a Participant in the Plan unless the affiliate has previously adopted the Plan. An affiliate of the Company may adopt this Plan only with the approval of the Board. By adopting this Plan, the affiliate shall be deemed to have agreed to assume the obligations and liabilities imposed upon it by this Plan, agreed to comply with all of the other terms and provisions of this Plan, delegated to the Plan Administrator, the Benefits Department, and the Administration Committee the power and responsibility to administer this Plan with respect to the affiliate's employees, and delegated to the Company the full power to amend or terminate this Plan with respect to the affiliate's employees. ARTICLE III SUPPLEMENTAL DEFERRALS AND CREDITS 3.1. Supplemental Deferral Agreement. In order to make Supplemental Deferrals, a Participant must execute a Supplemental Deferral Agreement in the form prescribed by the Benefits Department from time to time. In the Supplemental Deferral Agreement, the Participant shall agree to reduce his Compensation in exchange for a Supplemental Deferral in the same amount. The Supplemental Deferral Agreement shall be delivered to the Benefits Department by the time specified in Section 3.2(b). -3- 3.2. Supplemental Deferrals. (a) Amount. Any Participant may elect to defer, pursuant to a Supplemental Deferral Agreement, the receipt of a portion (designated in whole percentages) of the Compensation otherwise payable to him or her by the Company or an adopting affiliate in any Plan Year. The Participant's Supplemental Deferrals will begin only after the Participant has made the maximum pre-tax contributions to the MESP that are permitted under Section 402(g) of the Code or pursuant to the terms of the MESP document. The maximum amount of Compensation that may be deferred hereunder by a Participant shall be equal to six percent of the Compensation paid to the Participant during the part of the Plan Year that the Participant is eligible to make Supplemental Deferrals. The amount deferred pursuant to this paragraph (a) shall be referred to as a "Supplemental Deferral" and shall be allocated to the Supplemental Deferral Account maintained for the Participant for such Plan Year. (b) Timing of Elections. As a general rule, the Supplemental Deferral Agreement shall be signed by the Participant and delivered to the Benefits Department prior to January 1 of the Plan Year in which the Compensation to be deferred is otherwise payable to the Participant. The Supplemental Deferral Agreement will indicate whether it is to be effective for a single Plan Year or will remain in effect until properly changed by the Participant. For the Plan Year in which a Participant first becomes eligible to participate in the Plan, the Participant may elect to make Supplemental Deferrals from Compensation otherwise payable in the future during the then current Plan Year by signing and delivering a Supplemental Deferral Agreement within 30 days after the date he or she becomes eligible. Any election made by a Participant shall be irrevocable with respect to the Plan Year covered by the election. A Participant may, however, revoke the election for any later Plan Year by delivering to the Benefits Department a written instrument prior to the beginning of the Plan Year for which such revocation is to be effective. 3.3. Supplemental Matching and Employer Credits. Each Plan Year (or more frequently), the Recordkeeper shall allocate Supplemental Matching and Employer Credits to the Participant's Supplemental Employer Account. (a) Supplemental Matching Credit. Participants are not permitted to make deferrals pursuant to Section 3.2(a) until they have made the maximum pre-tax contributions to the MESP that are permitted under Section 402(g) of the Code or the terms of the MESP. This Plan is intended to put participants in the same position that they would have been in but for these limits on pre-tax contributions. Accordingly, the Supplemental Matching Credit shall be in an amount equal to the "lost MESP Matching Contribution." The "lost MESP Matching Contribution" is the MESP Matching Contribution that would have been due under the MESP if the deferrals under Section 3.2 for the Plan Year could have been contributed, instead, to the MESP. (b) Supplemental Employer Credit. The Supplemental Employer Credit shall equal (i) the MESP Employer Contribution that would have been made on the Participant's behalf to the MESP for the Plan Year if the contributions were not limited by the Code (including, particularly, the limitations imposed by Sections 401(a)(17) and 415 of the Code), reduced by (ii) the MESP Employer Contributions actually made to the MESP on behalf of the Participant in the Plan Year. -4- 3.4. Benefits Not Contingent. Deferrals and credits for any Participant under this Plan are not increased or decreased to the extent a Participant makes or does not make deferrals under the MESP. The Plan should be interpreted and administered in a manner that is consistent with this Section 3.4. ARTICLE IV INVESTMENT OF ACCOUNTS 4.1. Adjustment of Accounts. Except as otherwise provided elsewhere in the Plan, as of each Valuation Date, each Participant's accounts will be adjusted to reflect deferrals and credits under Article III and the positive or negative rate of return on the Investment Funds selected by the Participant pursuant to Section 4.2(b). The rate of return will be determined by the Recordkeeper pursuant to Section 4.2(f) and will be credited or charged in accordance with written policies applied to all Participants. While the accounts will be adjusted as of each Valuation Date, the Recordkeeper shall only post the adjustments as of the last business day of each month. 4.2. Investment Direction. (a) Investment Funds. Each Participant may direct the hypothetical investment of amounts credited to his accounts in one or more of the Investment Funds. The Investment Funds shall include a Company Stock Fund and such other investment funds as may be available under the MESP. The Investment Funds may be changed from time to time by the Administration Committee, in its discretion. (b) Participant Directions. Upon becoming a Participant in the Plan, each Participant may direct that all of the amounts attributable to his accounts be invested in a single Investment Fund or may direct that fractional (percentage) increments of his accounts be invested in such fund or funds as he shall desire in accordance with such procedures as may be established by the Committee. Unless the Committee prescribes otherwise, such procedures shall mirror the procedures established under the MESP for participant investment direction. A Participant's ability to direct investments into or out of the Company Stock Fund shall be subject to such procedures as the Company's General Counsel (or his delegate) may prescribe from time to time to assure compliance with Rule 16b-3 promulgated under Section 16(b) of the Securities Exchange Act of 1934, as amended, and other applicable requirements. Such procedures also may limit or restrict a Participant's ability to make (or modify previously made) elections. (c) Changes and Intra-Fund Transfers. Participant investment directions may be changed, and amounts may be transferred from one hypothetical Investment Fund to another, in accordance with the procedures established by the Committee (or, in the case of the Company Stock Fund, the General Counsel) pursuant to Section 4.2(b). The designation will continue until changed by the timely submission of a new designation. -5- (d) Default Selection. In the absence of any designation, a Participant will be deemed to have directed the investment of his accounts in such Investment Funds as the Committee, in its sole and absolute discretion, shall determine. (e) Impact of Election. The Participant's selection of Investment Funds shall serve only as a measurement of the value of the Participant's accounts pursuant to Section 4.1 and Section 4.2 and neither the Company nor the Committee are required to actually invest a Participant's accounts in accordance with the Participant's selections. (f) Rate Of Return. Accounts shall be adjusted on each Valuation Date to reflect investment gains and losses as if the accounts were invested in the hypothetical Investment Funds selected by the Participants in accordance with Section 4.2 and charged with any and all reasonable expenses related to the administration of the Plan including, but not limited to, the reasonable expenses of carrying out the hypothetical investment directions related to each account. The earnings and losses determined by the Recordkeeper in good faith and in its discretion pursuant to this Section shall be binding and conclusive on the Participant, the Participant's beneficiary and all parties claiming through them. (g) Charges. The Committee may direct the Recordkeeper to charge each Participant's accounts for the reasonable expenses of carrying out investment instructions directly related to such accounts. 4.3. Special Company Stock Fund Provisions. (a) General. A Participant's interest in the Company Stock Fund shall be expressed in whole and fractional hypothetical units of the Company Stock Fund. As a general matter, the Company Stock Fund shall track an investment in Company Stock in the same manner as the MESP's company stock fund. Accordingly, the value of a unit in the Plan's Company Stock Fund shall be the same as the value of a unit in the MESP's company stock fund. (b) Dividends and Stock Splits. If a cash dividend is declared on Company Stock, the hypothetical equivalent cash dividends attributable to the notional shares held in the Company Stock Fund shall be "reinvested" into the Company Stock Fund. If a stock dividend or share split is declared with respect to Company Stock, a hypothetical equivalent stock dividend or stock split attributable to the notional shares held in the Company Stock Fund, or any hypothetical securities issued with respect to the Company Stock Fund shall be allocated to the Company Stock Fund. All such hypothetical dividends (cash or stock) or stock splits shall be reflected appropriately in the Participant's accounts. 4.4. Compliance with Securities Laws. Any election by a Participant to hypothetically invest any amount in the Company Stock Fund, and any elections to transfer amounts from or to the Company Stock Fund to or from any other Investment Fund, shall be subject to all applicable securities law requirements, including but not limited to Rule 16b-3 promulgated by the Securities Exchange Commission. To the extent that any election violates any securities law requirement, the election shall be void. -6- ARTICLE V DISTRIBUTIONS 5.1. Right to Receive Distribution. Following a Participant's termination of employment for any reason, including death or "Change in Control" (as defined in the Public Service Company of New Mexico Executive Retention Plan, or any successor plan), the Participant's interest in this Plan will be distributed to the Participant at the time and in the manner provided in Sections 5.5 and 5.2. A transfer of a Participant from PNM to an affiliate that is authorized by the Board of Directors to adopt the Plan and that has adopted the Plan shall not be deemed a termination and such transfer shall not trigger a distribution of benefits under this Plan. 5.2. Form of Distribution. (a) Company Stock Fund. Subject to Section 5.4, the portion of a Participant's accounts that is allocated to the Company Stock Fund shall be distributed in a single lump sum payment in whole shares of Company Stock (with fractional shares paid for in cash) unless the Participant elects to receive a cash distribution. The election to receive cash or Company Stock shall be made at the time and in the manner provided in the form prescribed by the Benefits Department from time to time for that purpose. Any election made by a Participant pursuant to this Section with respect to a distribution from the Company Stock Fund shall be subject to all applicable securities law requirements, including but not limited to, Rule 16b-3. Any election that may not be implemented due to the lack of any available exemption shall be void. The Benefits Department may then make the distribution in any fashion that will not result in a violation of any applicable securities law requirements. The Benefits Department also may delay the distribution if necessary. An exemption to the securities law requirements that is only available with the prior approval of the Board, the shareholders or some other individual or individuals, shall not be considered to be available unless such approval is actually granted in a timely manner. (b) Non-Company Stock Investment Funds. The portion of a Participant's accounts that is not allocated to the Company Stock Fund shall be distributed in cash in a single lump sum payment. 5.3. Amount of Distribution. The amount distributed to a Participant shall equal the sum of the amounts credited to the Participant's Supplemental Deferral Account and Supplemental Employer Account as of the quarterly Valuation Date next following the Participant's termination of employment. For purposes of this Plan, a "quarterly Valuation Date" is a Valuation Date that coincides with the last business day of a calendar quarter. Shares of Company Stock that are distributed in cash will be valued at the closing price of the Company Stock on the New York Stock Exchange on the relevant quarterly Valuation Date. 5.4. Limits on Distributions of Company Stock. Notwithstanding anything to the contrary in this Plan, no individual officer or director of the Company may receive a distribution of Company Stock that exceeds more than one percent of the Company Stock that was outstanding as of the date of the adoption of this amendment and restatement of the Plan. Moreover, all Company Stock issued under this Plan, shall be limited to the amount of Company Stock that may be issued pursuant to Section 312.03(a)(4)(ii) of the New York Stock Exchange Listed Company Manual (generally, considering all Company plans, five percent of the Company Stock outstanding as of the date of the adoption of this amendment and restatement of the Plan). -7- 5.5. Timing of Distribution. Funds will be distributed within an administratively reasonable period of time (generally ten working days) following the applicable quarterly Valuation Date, unless prohibited by the Company's cash position. 5.6. Beneficiary Designation. If a Participant should die before receiving a full distribution of his or her Supplemental Deferral and Employer Accounts, distribution shall be made to the beneficiary designated by the Participant. If a Participant has not designated a beneficiary, or if no designated beneficiary is living on the date of distribution, such amounts shall be distributed to those persons entitled to receive distributions of the Participant's accounts under the MESP. The distributions made under this Plan shall be made in a lump sum. 5.7. Withholding. All distributions will be subject to all applicable tax and withholding requirements. 5.8. Deductibility. All amounts distributed from the Plan are intended to be deductible by the Company or the appropriate adopting affiliate. If all or any portion of a distribution will not be deductible, the payment of the nondeductible portion will be postponed until the first year in which it may be deducted. The distribution will be made during the first 60 days of such year. The unpaid amounts will continue to be adjusted pursuant to Article IV until the accounts have been distributed. ARTICLE VI ADMINISTRATION OF THE PLAN 6.1. Appointment of Committee. The Committee, which shall be known as the Administration Committee, shall consist of at least three members appointed by the Company. The Company may remove any member of the Committee at any time and a member may resign by written notice to the Company. Any vacancy in the membership of the Committee shall be filled by appointment made by the Company, but pending the filling of such vacancy the existing members of the Committee may act hereunder as though they alone constitute the full Committee. 6.2. Majority Rule and Delegation of Ministerial Acts. Any and all acts and decisions of the Committee shall, if there is more than one member, be by at least a majority of the current members, but the Committee may delegate to any one or more of its members or any other person the authority to sign notices or other documents on its behalf or to perform ministerial acts for it, in which event any other person may accept such notice, document or act without question as having been authorized by the Committee. If the majority of the current members of the Committee are unable to agree to an act or decision, the Committee shall seek instructions from the Company. 6.3. Meetings. The Committee may, but need not, call or hold formal meetings, and any decisions made or actions taken pursuant to written approval of a majority of the current members shall be sufficient. The Committee shall maintain adequate records of its decisions and those records shall be subject to inspection by the Company. Also, the Committee may designate one of its members as Chairman, and one of its members as Secretary, and may establish policies and procedures governing it so long as the same are not inconsistent with the terms of this Plan. -8- 6.4. General Powers and Duties. (a) General. The Committee shall perform the duties and exercise the powers and discretion given to it in this Plan document and its decisions and actions shall be final and conclusive as to all persons affected thereby. The Company and the adopting affiliates shall furnish the Committee with all data and information that the Committee may reasonably require in order to perform its functions. The Committee may rely without question upon any such data or information. (b) Disputes. Any and all disputes that may arise involving Participants or beneficiaries shall be referred to the Committee and its decision shall be final. Furthermore, if any question arises as to the meaning, interpretation or application of any provisions of this Plan, the decision of the Committee shall be final. (c) Conflicts of Interests. Notwithstanding any other provision of this Plan, during any period in which two or more Committee members are acting, no member of the Committee shall vote or act as a member of the Committee upon any matter involving the member's own rights, benefits or other participation hereunder. If a member of the Committee is recused pursuant to the preceding sentence, then the remaining Committee members may act as if they alone constitute the full Committee. (d) Agents. The Committee may engage agents, including actuaries, to assist it and may engage legal counsel who may be counsel for the Company. The Committee shall not be responsible for any action taken or omitted to be taken on the advice of such counsel, including written opinions or certificates of any agent, counsel, actuary or physician. (e) Insurance. At the Committee's request, the Company shall purchase liability insurance to cover the members of the Committee in their activities as the Committee. (f) Allocations. The Committee is given specific authority to allocate and revoke responsibilities among its members. When the Committee has allocated authority pursuant to this paragraph, the Committee is not to be liable for the acts or omissions of the party to whom such responsibility has been allocated. (g) Records. The Benefits Department shall supervise the establishment and maintenance of records by the Recordkeeper, the Company and each adopting affiliate containing all relevant data pertaining to any person affected hereby and his or her rights under this Plan. (h) Interpretations. The Committee, in its sole discretion, shall interpret and construe the provisions of the Plan (and any underlying documents or policies). -9- The foregoing list of powers and duties is not intended to be exhaustive, and the Committee shall, in addition, exercise such other powers and perform such other duties as it may deem advisable in the administration of the Plan, unless such powers or duties are assigned to another pursuant to the provisions of the Plan. 6.5. Claims. The Benefits Department will be responsible for the initial review of all claims. In the event that a Participant or beneficiary (the "claimant") is denied a claim for benefits under this Plan, the Benefits Department shall provide to the claimant written notice of the denial that shall set forth: (a) The specific reason or reasons for the denial; (b) Specific references to pertinent Plan provisions on which the Benefits Department based its denial; (c) A description of any additional material or information needed for the claimant to perfect the claim and an explanation of why the material or information is needed; (d) A statement that the claimant may: (i) Request a review by the Committee upon written application to the Benefits Department; (ii) Review pertinent Plan documents; and (iii) Submit issues and comments in writing. (e) That any appeal the claimant wishes to make of the adverse determination must be in writing and must be delivered to the Committee within 60 days after receipt of the Benefits Department notice of denial of benefits. The Benefits Department notice must further advise the claimant that his failure to appeal the action to the Committee in writing within the 60 day period will render the Benefits Department determination final, binding, and conclusive. 6.6. Appeals. If the claimant should appeal to the Committee, he, or his duly authorized representative, may submit in writing whatever issues and comments he, or his duly authorized representative, feels are pertinent. The Committee shall re-examine all facts related to the appeal and make a final determination as to whether the denial of benefits is correct. The Committee shall advise the claimant in writing of its decision on his appeal, the specific reasons for the decision, and the specific Plan provisions on which the decision is based. The notice of the decision shall be given within 60 days of the claimant's written request for review, unless special circumstances (such as a hearing) would make the rendering of a decision within the 60 day period infeasible, but in no event shall the Committee render a decision regarding the denial of a claim for benefits later than 120 days after its receipt of a request for review. If an extension of time for review is required because of special circumstances, written notice of the extension shall be furnished to the claimant prior to the date the extension period commences. -10- ARTICLE VII AMENDMENT OR TERMINATION 7.1. Amendment or Termination. The Company intends the Plan to be permanent but reserves the right to amend or terminate the Plan when, in the sole discretion of the Company, such amendment or termination is advisable. Any such amendment or termination shall be made pursuant to a resolution of the Board and shall be effective as of the date of such resolution. 7.2. Effect of Amendment or Termination. Any amendment or termination of this Plan shall apply prospectively only and shall not directly or indirectly reduce the balance of any Plan account as of the effective date of such amendment or termination. Upon termination of the Plan, distribution of amounts in Supplemental Deferral and Supplemental Employer Accounts shall be made to the Participant or his or her beneficiary in the manner and at the time described in Article V of the Plan. No additional credits of Supplemental Deferrals or Supplemental Matching and Employer Credits shall be made to the Supplemental Deferral and Supplemental Employer Accounts of a Participant after termination of the Plan, but the Company may continue to credit or charge gains and losses to the Supplemental Deferral and Supplemental Employer Accounts, until the balance of such Supplemental Deferral and Supplemental Employer Accounts has been fully distributed to the Participant or his or her beneficiary. ARTICLE VIII GENERAL PROVISIONS 8.1. Participant's Rights Unsecured. The Plan at all times shall be entirely unfunded and no provision shall at any time be made with respect to segregating any assets of the Company for payment of any distributions hereunder. The right of a Participant or his or her designated beneficiary to receive a distribution hereunder shall be an unsecured claim against the general assets of the Company, and neither the Participant nor a designated beneficiary shall have any rights in or against any specific assets of the Company. All amounts credited to a Participant's Supplemental Deferral and Supplemental Employer Accounts shall constitute general assets of the Company and may be disposed of by the Company at such time and for such purposes as it may deem appropriate. Nothing in this Section shall preclude the Company from establishing a "Rabbi Trust", but the assets in the Rabbi Trust must be available to pay the claims of the Company's general creditors in the event of the Company's insolvency. 8.2. No Guaranty of Benefits. Nothing contained in the Plan shall constitute a guaranty by the Company or any other person or entity that the assets of the Company will be sufficient to pay any benefit hereunder. 8.3. No Enlargement of Employee Rights. No Participant shall have any right to receive a distribution from the Plan except in accordance with the terms of the Plan. Establishment of the Plan shall not be construed to give any Participant the right to be retained in the service of the Company. 8.4. Spendthrift Provision. No interest of any person or entity in, or right to receive a distribution under, the Plan shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment, or other alienation or encumbrance of any kind; nor shall any such interest or right to receive a distribution be taken, either voluntarily or involuntarily, for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims in bankruptcy proceedings. This Section shall not preclude arrangements for the withholding of taxes from deferrals, credits, or benefit payments, arrangements for the recovery of benefit overpayments, arrangements for the transfer of benefit rights to another plan, or arrangements for direct deposit of benefit payments to an account in a bank, savings and loan association or credit union (provided that such arrangement is not part of an arrangement constituting an assignment or alienation). -11- 8.5. Applicable Law. The Plan shall be construed and administered under the laws of the State of New Mexico, except to the extent preempted by the Employee Retirement Income Security Act of 1974, as amended. 8.6. Incapacity of Recipient. If the Benefits Department is served with a court order holding that a person entitled to a distribution under the Plan is incapable of personally receiving and giving a valid receipt for such distribution, the Benefits Department shall postpone payment until such time as a claim therefor shall have been made by a duly appointed guardian or other legal representative of such person. The Benefits Department is under no obligation to inquire or investigate as to the competency of any person entitled to a distribution. Any payment to an appointed guardian or other legal representative under this Section shall be a payment for the account of the incapacitated person and a complete discharge of any liability of the Company and the Plan therefor. 8.7. Successors. This Plan shall be binding upon the successors and assigns of the Company and upon the heirs, beneficiaries and personal representatives of the individuals who become Participants hereunder. 8.8. Unclaimed Benefit. Each Participant shall keep the Benefits Department informed of his or her current address and the current address of his or her designated beneficiary. The Benefits Department shall not be obligated to search for the whereabouts of any person. If the location of a Participant is not made known to the Benefits Department within three years after the date on which payment of the Participant's Supplemental Deferral and Supplemental Employer Accounts may first be made, payment may be made as though the Participant had died at the end of the three year period. If, within one additional year after such three year period has elapsed, or, within three years after the actual death of a Participant, the designated beneficiary of the Participant has not been located, then there shall be no further obligation to pay any benefit hereunder to such Participant or designated beneficiary and such benefit shall be irrevocably forfeited. 8.9. Limitations on Liability. Notwithstanding any of the preceding provisions of the Plan, neither the Plan Administrator, the Benefits Department or the Committee, nor any individual acting as the Plan Administrator's, the Benefits Department's, the Committee's, or the Company's employee, agent, or representative shall be liable to any Participant, former Participant or other person for any claim, loss, liability or expense incurred in connection with the Plan. -12- 8.10. Headings for Convenience Only. The headings and subheadings of this Plan are inserted for convenience and reference only and are not to be used in construing this instrument or any provision herein. 8.11. Severability. If any provision of this Plan is held to be illegal or invalid, such illegality or invalidity shall not affect the remaining provisions of this Plan, and the remaining provisions shall be construed and enforced as if such illegal or invalid provision had never been inserted herein. 8.12. Conflicts. If any person holds a position under this Plan through which he or she is charged with making a decision about his or her own (or any immediate family member's) Plan participation, including, without limitation, eligibility, account valuation, or investments, then such person shall be recused and the decision shall be made by the Committee. IN WITNESS WHEREOF, the Company has caused this Plan to be executed by its duly authorized officer on the date and year first above written. PUBLIC SERVICE COMPANY OF NEW MEXICO /s/ Jeffry E. Sterba ------------------------------------ Jeffry E. Sterba, Chairman, President and CEO -13- EX-21 6 exh_21.txt EXHIBIT 21 EXHIBIT 21 Certain Subsidiaries of PNM Resources, Inc. As of December 31, 2001, PNM Resources, Inc. directly owns all of the voting securities of the following "significant subsidiary" (as defined in Rule 1-02(v) of Regulation S-X): Public Service Company of New Mexico a New Mexico corporation. Public Service Company of New Mexico does business under the names "PNM", "PNM Electric and Gas Services", "PNM Electric Services" and "PNM Gas Services". The remaining subsidiaries of PNM Resources, Inc. (including Avistar, Inc., a New Mexico corporation), considered in the aggregate as a single subsidiary, do not constitute a "significant subsidiary" as of the end of the year covered by this report. EX-23 7 exh_231.txt CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS Exhibit 23.1 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included in this Form 10-K, into the Company's previously filed Registration Statement File No. 33-65418, Registration Statement File No. 333-03289, Registration Statement File No. 333-03303, Registration Statement File No. 333-10993, Registration Statement File No. 333-32170, Registration Statement File No. 333-53367, Registration Statement File No. 333-61598, Registration Statement File No. 333-73648, Registration Statement File No. 333-76288, and Registration Statement File No. 333-76316. Albuquerque, New Mexico March 26, 2002 EX-99 8 exh_9923.txt CONFIRMATION OF ARTHUR ANDERSEN REPRESENTATION Exhibit 99.23 PNM Resources, Inc. Public Service Company of New Mexico Alvarado Square Albuquerque, New Mexico 87185 March 26, 2002 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 PNM Resources, Inc. and Public Service Company of New Mexico have obtained representation from their external auditors, Arthur Andersen LLP ("Andersen"), that their audits were subject to Andersen's quality control system for the U.S. accounting and auditing practice to provide reasonable assurance that the audits were conducted in compliance with professional standards, that there was appropriate continuity of personnel working on the audits and technical consultation was available from the national office. The availability of personnel at foreign affiliates was not applicable to these audits. Very Truly Yours, /s/ John R. Loyack ------------------------------------------------ John R. Loyack Vice President, Corporate Controller and Chief Accounting Officer -----END PRIVACY-ENHANCED MESSAGE-----