PNM successfully completed a number of long-term contracts during 2003. In September 2003, PNM entered into a long-term contract to supply between 15 and 25 MW of power to Overton Power District Number 5 in Southern Nevada. The contract began October 1, 2003 and runs through December 31, 2007. In October of 2003, PNM completed a five-year contract to sell Salt River 50 megawatts of wind power and associated renewable energy credits from the NMWE for the third quarter of each year from 2004 through 2008. In December 2003, PNM completed an agreement to supply up to 35 megawatts of power to the Mesa, Arizona, municipal utility. PNM is replacing Ohio-based American Electric Power (AEP) as supplier under a contract that runs through 2013. 

## Coal Supply 

The coal requirements for the SJGS are being supplied by San Juan Coal Company (“SJCC”), a wholly-owned subsidiary of BHP Billiton. SJCC holds certain Federal, state and private coal leases under an underground coal sales agreement (“coal agreement”) pursuant to which it will supply processed coal for operation of the SJGS until 2017. The coal agreement is a cost plus contract. SJCC is reimbursed for all costs for mining and delivering the coal plus an allocated portion of administrative costs. In addition, SJCC receives a return on its investment. BHP Minerals International, Inc. has guaranteed the obligations of SJCC under the coal agreement. This guarantee is with respect to SJCC’s obligations as defined in the coal agreement and protects against contingencies such as SJCC non-performance, insolvency, bankruptcy, reorganization, dissolution, and other corporate or organizational adversities. The coal agreement contemplates the delivery of approximately 91 million tons of coal during its remaining term. That amount would supply substantially all the requirements of the SJGS through approximately 2017. 

In August 2001, the Company and Tucson Electric Power Company (“Tucson”) signed the coal agreement with SJCC to replace two surface mining operations with a single underground mine located adjacent to the plant. The initial development of the underground mine began in the fourth quarter of 2000. After the longwall equipment became operational in October 2002, the mine was expected to achieve full station supply in March of 2003. It did not achieve this production level until December 2003, necessitating partial coal supply from existing inventory. Despite geological issues that impeded the underground mine production rates and efficiencies that were expected, SJGS fuel costs declined by 3.5% between 2002 and 2003. SJCC and the Company continually review coal cost projections and work with the Company’s mine consultants to incorporate the experience gained from the first full year mining operations. 

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 which has been recently extended, expires July 6, 2016. The extension of the agreement did not materially affect the coal cost forecast. 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. 

In connection with both the SJGS coal agreement and the Four Corners fuel agreement, the owners are required to reimburse SJCC and BNCC for the cost of coal mine decommissioning or reclamation. Final mine reclamation occurs when mining production activities conclude. The Company considers these costs part of the cost of delivered coal costs over the life of the respective mine. This liability is recorded at estimated fair value based on the expected cash out-flows to be made to reimburse SJCC and BNCC for their reclamation activities. These cash flows are discounted at a credit adjusted risk-free rate. The liability is accreted and an appropriate incremental cost is recognized using the interest method. 

In 2003, the Company completed a comprehensive review with the help of an outside consulting firm of the final reclamation costs for both the surface mines that previously provided coal to SJGS and the current underground mine providing coal. Based on this study, the Company revised its estimates of the final reclamation of the surface mine. In addition, the mining contract with BNCC supplying Four Corners was renewed until 2016. Previously the Company had recognized obligations related to these surface mines of $113.9 million. Based on these changes in estimate, the final cost of reclamation is expected to be $139.3 million in accreted dollars. In 2002 and 2003, the Company made payments of $36.6 million and $12.9 million, respectively, against this liability. As of December 31, 2003, $56.9 million was recognized as the Company’s obligation for reclamation using the fair value method to determine the liability. 

In the Global Electric Agreement (see “Global Electric Agreement” below), the Company was allowed to collect $100 million of surface mine final reclamation costs over the next 17 years. The Company expects to recover the remaining amount in a future rate case. In addition, the Company expects to recover the portion of final underground mine reclamation costs related to New Mexico ratepayers in future rate cases. 

The underground mine began commercial operation in January 2003. The Company recognized a reclamation liability of $0.6 million related to mining activities in 2003. 

## Natural Gas Supply 

The Company contracts for the purchase of gas to serve its retail customers. These contracts are short-term in nature supplying the gas needs for the current heating season and the following off-season months. The price of gas is a pass-through, whereby the Company recovers 100% of its cost of gas. 

The natural gas used as fuel by Electric and Wholesale was delivered by Gas. In the second quarter of 2001, Electric and Wholesale began procuring its gas supply independent of the Company and contracting with Gas for transportation services only. 

## 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 assessed on an on-going basis. Two replacement steam generators were installed in Unit 2 during its Fall 2003 refueling outage. The Company’s share of the fabrication and installation costs were approximately $24.7 million as of December 31, 2003. 

The PVNGS participants (“Participants”) have approved the purchase of replacement steam generators for Units 1 and 3. Preliminary work for the installation of the replacement steam generators has also been approved by the Participants. These actions will provide the Participants with options regarding the replacement of steam generators in Unit 1 and Unit 3. Unit 1 could be replaced as early as Fall 2005, should the Participants choose to do so. The Company estimates that its portion of the fabrication and installation costs and associated power upgrade modifications for Units 1 and 3, will be approximately $46 million over the period 2002-2008 (exclusive of replacement power costs), should installation of the ordered replacement steam generators be approved. 

## PVNGS Decommissioning Funding 

PNM has a program for funding its share of decommissioning costs for PVNGS. The nuclear decommissioning funding program is invested in equities and fixed income instruments in qualified and non-qualified trusts. The results of the 2001 decommissioning cost study indicated that PNM’s share of the PVNGS decommissioning costs, excluding spent fuel disposal, would be approximately $201 million (measured in 2001 dollars). 

PNM provided an additional $3.1 million, $10.7 million and $6.1 million funding for the year ended December 31, 2003, 2002 and 2001, respectively, into the qualified and non-qualified trust funds. The estimated market value of the trusts for the year ended December 31, 2003 was approximately $78.7 million. 

## Nuclear Spent Fuel and Waste Disposal 

Pursuant to the Nuclear Waste Policy Act of 1982, as amended in 1987 (the “Waste Act”), the United States Department of Energy (“DOE”) is obligated to accept and dispose of all spent nuclear fuel and other high-level radioactive wastes generated by domestic power reactors. 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. The DOE has announced that such a repository cannot be completed before 2010. 

The operator of PVNGS has fuel storage pools at PVNGS, which accommodates fuel from normal operation of PVNGS. To continue to allow full core offload capability, older fuel is being placed in dry storage casks and removed from the Units. Through December 31, 2003, the operator of PVNGS has loaded 10 dry storage casks and placed the casks in the completed dry storage facility. Fuel from Unit 3 will be removed from the Unit 3 fuel storage pool during the first quarter of 2004. PNM currently estimates that it will incur approximately $41.0 million (in 2001 dollars) over the life of PVNGS for its share of the fuel costs related to the on-site interim storage of spent nuclear fuel during the operating life of the plant. PNM accrues these costs as a component of fuel expense, meaning that the charges are accrued as the fuel is burned. The Company has accrued $1.0 million in each of 2003 and 2002 for interim storage costs. 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. The dry storage facility has the space to hold all fuel anticipated to be used during the licensed life of PVNGS. 

## PVNGS Liability and Insurance Matters 

The Participants have financial protection for public liability resulting from nuclear energy hazards to the full limit of liability under federal law. This potential liability is covered by primary liability insurance provided by commercial insurance carriers in the amount of $300.0 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. Effective August 20, 2003, the maximum assessment per reactor under the program for each nuclear incident increases from approximately $88 million to approximately $101 million. The retrospective assessment is subject to an annual limit of $10.0 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 $31 million, with an annual payment limitation of approximately $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. 

## Possible Price-Anderson Act Changes 

Versions of comprehensive energy bills proposed for adoption by Congress contain provisions that would amend Federal Law (the “Price-Anderson Act”) addressing public liability from nuclear energy hazards in ways that would increase the annual limit on retrospective assessments (see “PVNGS Liability and Insurance Matters” above) from $10.0 million to $15.0 million per reactor per incident with the Company’s annual exposure per incident increasing from approximately $3.0 million to $4.5 million. 

The Company believes that such changes in applicable law, if enacted, would not result in a “deemed loss event” being declared by the equity investors in respect of the Company’s sale and leaseback transactions of PVNGS Units 1 and 2. 

