ML023100359

Part 7 of 10, Palo Verde, 2001 Annual Financial Report, Pnm Resources 2001 Annual Report

ML023100359
Person / Time
Site:	Palo Verde
Issue date:	10/30/2002
From:	Bauer S Arizona Public Service Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
102-04859-SAB/TNW/CJJ
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Text

we have the power R e p o r t R E S O U R C E S A n n u a l P N M 2 0 0 1 W E H A V E T H E P O W E R P N M R E S O U R C E S 2 0 0 1 A N N U A L R E P O R T

investor highlights: Dollars in thousands, except per share amounts.

P E R C E N TA G E 5-YEAR ANNUAL 2001 2000 CHANGE G R O W T H R AT E Financial Data:

Operating Revenues $2,352,098 $1,611,274 46.0% 21.9%

Operating Expenses $2,129,421 $1,478,800 44.0% 23.3%

Net Earnings Available for Common $ 149,847 $ 100,360 49.3% 15.8%

Retained Earnings $ 415,388 $ 296,843 39.9% 40.0%

Return on Average Common Equity 14.8% 11.1% 33.3% 8.6%

Common Shar e Data:

Earnings (Basic) $ 23.83 $ 22.54 50.8% 17.4%

Earnings (Diluted) $ 23.77 $ 22.53 49.0% 17.1%

Book Value $ 25.87 $ 23.64 9.4% 7.5%

Closing Price $ 27.95 $ 26.81 4.3% 7.3%

Dividends Paid $ 20.80 $ 20.80 N/M 17.3%

Average Shares Outstanding 39,118 39,487 -0.9% -1.3%

Number of Employees: 2,675 2,667 0.5% -0.5%

N/M = Not Meaningful PNM Resources is a holding company whose primary subsidiary is PNM, an electric and gas utility based in Albuquerque, New Mexico. The company also sells power on the wholesale market in the Western U.S. PNM Resources stock is traded primarily on the NYSE under the symbol PNM.

We had a great year. Our electric and gas utility continued to provide customers with reliable service at affordable prices, while our wholesale power marketing business adapted successfully to rapid swings in prices. Were working harder and smarter than ever. Our aim is to build Americas best merchant utility. We have the power.

A few of the 2,675 PNM and Cover PNM Resources employees who make it all possible.

Company Overview 3 Letter to Shareholders 13 Financial Information 17 Shareholder Information 88 Board of Directors Inside Back Cover

we have the power to grow 3 our wholesale business. Efficient generating plants, strategically located on the Western power grid, coupled with years of experience in the wholesale market have enabled us to grow our wholesale revenues from $185.3 million in 1997 to

$1.4 billion in 2001. To support continued expansion in our wholesale business, we are investing in two new power plants in 2002. We expect to add additional generating capacity over the next several years, as we have new customers ready to buy that additional power.

S A N J U A N G E N E R AT I N G S TAT I O N - Waterflow, New Mexico

Im responsible for repair and maintenance, custodial work, landscaping - its a big job, and always changing, says Nick King, operations Providing excellent Customers look to us to help manager for the 900,000 square-foot Winrock customer service is our streamline their businesses personal commitment and save money. Center retail mall in Albuquerque. As my PNM to New Mexico. Manuel Quintana Lynette Henry Business Manager, account representative, Lynette makes my life easier.

PNM Market Services PNM Market Services With her, I know I have somebody that listens to me, pays attention and gets me what I need.

4 we have the power to deliver 5 quality customer service. Our core business is delivering efficient, reliable, affordable electric and gas service to the people of New Mexico. This traditional, regulated distribution business now accounts for about 40 percent of PNM revenues and provides us with a steady cash flow and predictable earnings.

Demand for electric power in our service territory has been growing at a rate above the national average over the past five years, and we expect that growth will continue in 2002 and beyond. Over the past two years, we have invested more than

$200 million to expand our customer phone center and expand and upgrade our electric and gas distribution systems to boost reliability. In 2001, we installed a new, computerized outage response system designed to track outages, speed response time and keep customers better informed.

we have the power to create 7 shareholder value. Over the past five years, shareholders earned a 68.6 percent total return on their investment in PNM. In February 2002, the PNM Resources Board of Directors approved a 10 percent increase in the quarterly dividend, bringing the annual rate up to 88 cents per share. The increased dividend reflects financial performance in recent years and managements confidence in your companys future.

PNM Resources ample liquidity and strong balance sheet will enable us to fund the planned expansion of generation, new investment in our utility system and future dividend increases, while maintaining our companys financial strength. We plan to continue to raise the dividend by between 8 and 10 percent a year, until dividend payout equals between 50 and 60 percent of the earnings from our regulated utility operations.

Students at an Albuquerque elementary school absorb the basics of physics and engineering by building bridges with toy blocks.The idea came from teacher Tabitha Hall; Gifted kids need lots of We aim to encourage the blocks were provided through a grant from the non-profit hands-on experience. innovative approaches to Given that, theyre capable learning that we think can PNM Foundation. Other PNM programs support higher of learning very high-level really make a difference.

concepts very young. Diane Harrison Ogawa education, encourage energy conservation, and assist Tabitha Hall PNM Foundation Teacher disadvantaged residential customers with their energy bills. With company support and encouragement, employees also volunteer thousands of hours of their own time to support the communities we live in.

8 we have the power to lead 9 community and environmental initiatives. As New Mexicos oldest and largest public company, PNM takes the lead in promoting the economic vitality of our home state, enhancing the quality of life in the communities we serve, and preserving the environment we all share.

PNMs systematic approach to environmental stewardship sets priorities and monitors the impact of all our business activities throughout the company, holding each operating unit accountable for its performance. Although our plants already meet or exceed all federal and state clean air and water standards, PNM continues to invest in improving its performance. Our coal-fired San Juan Generating Station has cut sulfur dioxide emissions by half over the last four years.

we have the power to build Americas best merchant utility. 11 A merchant utility is first and foremost a provider of regulated utility service in a local environment and, at the same time, a supplier and trader in a competitive commodity market. We believe we have demonstrated the value to both our customers and our shareholders of operating in both these areas. Our wholesale power revenues help keep PNM retail rates low, and all customers share in the benefits of system reliability and the availability of PNMs low-cost generating resources.

Shareholders benefit from the steady dividend supported by our regulated utility business, together with the opportunity for stock price appreciation made possible by the growth in our wholesale marketing. Our intent is to expand our footprint in both such that we rely on the distribution utility for stability and power generation and trading for growth.

fellow shareholders, 2001 was the most tumultuous year I can recall in my 24 years in the energy industry. We saw extremely high price volatility in both gas and electricity markets, the California meltdown, growing debate over industry restructuring at both the federal and state level, the bankruptcy of one of the largest utilities in the United States and the collapse of the nations largest energy trader.

Despite all this turmoil, PNM closed 2001 with the highest level of earnings in the history of the company, earning $3.77 a share on operating revenues of over $2.35 billion. Total return for PNM shareholders, including price appreciation and dividends, was a positive 7.2 percent, compared to total returns for both the Dow Jones Industrial Index and the S&P 500 Index of negative 25.8 percent and negative 11.9 percent, financial strength (retained earnings in millions) respectively, for the year.

$415 Underlying our financial performance is the hard work of the men and women of PNM: $297

$228

• Our quality initiative is driving service and cost improvements. $186 letter from the chairman Getting Better Faster has become a personal commitment in our

$129 13 service delivery business.

• We kept PNM gas customer bills down among the lowest in our region by managing our gas purchases and implementing cost-smoothing billing mechanisms, despite sharply higher gas prices in the winter of 2000-01. 97 98 99 00 01

• PNM retail electric rates today are 13 percent below where they were in 1985 - a 45 percent decrease when adjusted for inflation -

and below the national average.

• Our wholesale trading operation weathered the electricity price storm in the West and turned in another stellar performance for the year, increasing revenues by 91 percent.

• We formed our new holding company, PNM Resources, giving us the corporate flexibility we need for future growth.

Our successes in 2001 did not come without some setbacks. Our single greatest disappointment was the collapse of our proposed acquisition of the electric utility business of Western Resources in Kansas. This outcome will not discourage us from other opportunities as they become available, however. One never succeeds by doing only that which is guaranteed.

L E T T E R F R O M T H E C H A I R M A N L E T T E R F R O M T H E C H A I R M A N Even that which seems guaranteed can change dramatically. We entered 2001 with just 12 months to go effort was begun by our former chairman, president and CEO John Ackerman, who retired from the PNM before we were scheduled to open our retail market in New Mexico to customer choice. That transition Board in 2001. John, who now teaches Business Ethics and Corporate Governance at the University of New has now been postponed until 2007. Mexico, led our board in codifying the standards we now live by at PNM.

At the federal level, the ongoing debate on energy policy and environmental legislation could I would also like to thank former Secretary of the Interior Manuel Lujan, who also retired from our Board significantly change the landscape for our industry. Unfortunately, much of this debate has been clouded last year. Manny has been a trusted advisor during his tenure with the Board, and his many years of by the failure of Enron, confusion over the operation of competitive electricity markets, and doubts about experience in Congress and as a leading figure in New Mexico proved invaluable to our company.

the accuracy of audited financial reports. In this regard, It is a pleasure to have two exceptional individuals its important to remember that Enrons collapse recently join the Board, Martin Chavez, Ph.D., CEO of productivity electric sales was not caused by utility industry restructuring or (customers per employee) (total MWh in millions)

Kiodex, has extensive experience in commodity risk by competition in the energy markets.

management, particularly in the energy area. Dr. Manuel Competitive forces have had a marked impact Pacheco, President of the University of Missouri System, 306 19.8 301 19.4 on our industry, establishing a higher standard of adds his experience in strategy and organizational 295 17.9 excellence. Competition has made PNM a better management. Both of these individuals are already adding 286 company, and our customers have reaped the benefit. to the Boards ability to guide our company through the 14 15.5 15 272 It has enabled the wholesale energy markets to changes ahead.

13.3 operate effectively in the face of Enrons demise.

We face significant challenges in 2002. At this writing, But it has also produced some outcomes that have wholesale power prices remain below what we believe met with objection, primarily due to poor design.

are sustainable levels. With the expiration of PNMs existing The challenge is to find ways to gain the retail rate freeze in 2003, we are seeking to reach an equitable Jeff Sterba Chairman, President and CEO 97 98 99 00 01 97 98 99 00 01 long-term benefits of competitive markets while resolution that is fair to both customers and shareholders.

providing the levels of service, predictability and We will also be addressing the need to add renewable convenience that consumers want. Policymakers resources to our generation mix.

must resist the trap of believing they can have the benefits competition brings while layering on regulation Our successes in 2001 came through hard work in executing a sound strategy. We are committed to to guard against occasional unwanted outcomes.

continuing this success in the years ahead. I thank you for your confidence in PNM Resources.

Increased competition and the expansion of our power generation and trading operation have caused Sincerely, us to adopt a more systematic, enterprise-wide approach to risk management. Our asset-backed trading strategy, which bases our trades on the power available from PNMs own plants, provides a fundamental physical hedge against exposure to price volatility in the marketplace. Our risk management team, headed by CFO Max Maerki, is charged with taking a structured, rigorous approach to all the operational and strategic risks we face.

Our risk management strategy starts with a strong commitment to ethical business conduct. Our Do the Jeff Sterba Right Thing approach to ethics has become engrained in our corporate culture over the last 10 years. This Chairman, President and CEO

financial information 18 Selected Financial Data 19 Managements Discussion and Analysis 51 Managements Responsibility for Financial Statements and Report of Independent Public Accountants 52 Financial Statements 58 Notes to Consolidated Financial Statements PNM Resources, Inc. (the Company) considers this annual report to contain forward-looking statements under Federal securities law. It is published to assist shareholders in evaluating the Company and its securities. This report does not contain all of the information material to an evaluation and should be read in conjunction with its periodic reports, proxy statement and other information the Company files with the Securities and Exchange Commission. Please refer to page 35,Disclosure Regarding Forward-Looking Statements, for a listing of the factors which could cause the Companys actual financial results to differ materially from the prospective information provided by the Company in forward-looking statements.

PNM RESOURCES, INC. AND SUBSIDIARIES selected financial data The selected financial data should be read in conjunction with the consolidated financial statements, the notes to consolidated financial statements and Managements Discussion and Analysis of Financial Condition and Results of Operations.

YEAR ENDED DECEMBER 31, 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) $2,889,917) $2,723,268) $2,668,603) $2,407,410) 18 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations The following is managements assessment of the Companys financial condition and the significant factors affecting the results of operations. This discussion should be read in conjunction with the Companys 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, 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. The Companys principal business seg-ments 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 Companys 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 19 its customers under the jurisdiction of the New Mexico Public Regulation Commission (PRC). As a merchant, the Company markets excess production from the utility, as well as, unregulated generation and its purchases for resale into a competitive market place. The merchant operations utilize an asset-backed trading strategy, whereby the Companys aggregate net open position for the sale of electricity is covered by the Companys 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 Companys 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 Companys ability to generate funds for the Companys expansion.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations RESULTS OF OPERATIONS Y E A R E N D E D D E C E M B E R 3 1 , 2 0 0 1 C O M PA R E D T O Y E A R E N D E D D E C E M B E R 3 1 , 2 0 0 0 Consolidated The Companys 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 discus-sions 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 20 (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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations The following discussion is based on the financial information presented in the Consolidated Financial Statements - Segment Information. The tables below set forth the operating results for each business segment note.

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 21 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 22 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 Companys 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 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Companys 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 23 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 Companys Generation and Trading Operations and is eliminated in the consolidated results.

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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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.

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 24 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 sales 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).

The gross margin, or operating revenues minus cost of energy sold, increased $141.7 million or 43.6%. The Companys margins benefit significantly from rising gas prices as most of the Companys 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 Companys stable low-cost generation increases significantly.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations Margins also benefited from the Companys 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 Companys gas generation facilities, which has a higher cost of production than the Companys 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.

25 Unregulated Businesses In July 2001, the Board of Directors of Avistar decided to wind down all unregulated operations except for Avistars 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 Avistars 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.

Due to the cessation of much of Avistars 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 reorgani-zational 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 Companys 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys 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.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999 Consolidated The Companys net earnings available to common shareholders for the year ended December 31, 2000 were $100.4 million, a 22%

26 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 enu-merates 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)

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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.

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 27 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 reduc-tion 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 Companys 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.

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 main-tenance 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations customer billing system on the collection of certain taxes and an increase in expected tax liabilities. Franchise fees were a part of the Companys 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 Companys 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 28 Average customers 435,000 426,000 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

$2.0 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 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: 29 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 Companys 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 Companys 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.

Taxes other than income increased $2.2 million or 24.6% due to higher tax liabilities.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Avistars 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 Companys 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 Companys terminated Western Resources transaction. In addition, other income and deductions included a valuation loss recognized for Avistars AMDAX.com investment, and expenses related to the transfer of the operation of the City of Santa Fes 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.

30 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 Companys 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 Companys 2000 income tax effective rate, before the cumulative effect of the accounting change, was 42.41%. Included in the Companys 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 Companys effective tax rate was 38.67%. The Companys 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.

FUTURE EXPECTATIONS Because of the wholesale market price decline in the Western United States that began in the second half of 2001, the Companys 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 Companys 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 whole-sale prices in the West do not increase as forecasted by the Company, the Companys 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 Companys 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 Companys 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Companys 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 Companys 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 dif-ferent assumptions. Management has identified the following accounting policies that it deems critical to the portrayal of the Companys 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.

Revenue Recognition The Company recognizes revenues in the period of delivery. The Companys Utility Operations are required to estimate revenues for unbilled services when its billing cycle does not match the calendar-end reporting period. Managements estimates are based on models which utilize actual units delivered and the applicable rate structure. 31 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 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 Managements 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 Companys 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 Companys mark-to-market adjustment for its trading contracts from December 31, 2000 to December 31, 2001.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations The following table summarizes the Companys 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 Companys 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 Companys 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 Companys 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 method-ology that considers the credit ratings of the Companys counterparties, the price volatility in the marketplace, the fair market value of all contracts outstanding and managements evaluation of market trends that are expected to impact market risk. The 32 resulting amount is recorded as an adjustment to revenue. Increases in market prices, increases in an individual counterpartys credit position and general economic conditions which may impact the credit ratings of the Companys 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 predecessor, and the Federal Energy Regulatory Commission (FERC). Substantially all of the Companys 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 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Companys 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 Companys 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. Managements estimates are based on its knowledge of the relevant facts at the time of the issuance of the Companys Consolidated Financial Statements.

Subsequent developments could materially alter managements assessment of a matters probable outcome and the estimate of the Companys 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 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).

33 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 Companys 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 Companys 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 Companys net peri-odic benefit cost assumed a 7.75% rate of return as compared to 9.00% in the prior year. The rate adjustment reflects the Companys outlook for asset returns after considering the events of September 11, 2001 and the impact of asset losses recog-nized in the September 30, 2001 plan valuation. This change resulted in an increase of $4.2 million in the Companys recorded

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 plans 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 Companys future results of operations to the extent that future calculations of the net periodic benefit expenses 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 Companys 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 Companys 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.

34 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 Companys ongoing competitive strategy of increasing generation capacity over time. The costs of these plants are not anticipated to be added to the rate base.

The Companys 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 Company has a $20.0 million reciprocal borrowing agreement with PNM and $25.0 million in local lines of credit.

The Companys 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.

PNMs credit outlook is considered positive by Moodys Investor Services (Moodys) and stable by Standard and Poors (S&P). Previously, in connection with PNMs announcement of its agreement to acquire Western Resources electric utility operations, S&P, Moodys and Fitch Ratings (Fitch) placed the PNMs 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 PNM to terminate the transaction in January 2002, S&P, Moodys and Fitch removed the Company from negative credit watch. PNM is committed to maintaining its investment grade. S&P currently rates PNMs senior unsecured notes

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations (SUNs) and its Eastern Interconnection Project (EIP) senior secured debt BBB-and its preferred stock BB. Moodys rates PNMs SUNs and senior unsecured pollution control revenue bonds Baa3; and preferred stock Ba1. The EIP senior secured debt is also rated Ba1. Fitch rates PNMs SUNs and senior unsecured pollution control revenue bonds BBB-,PNMs EIP lease obligation BB+and PNMs preferred stock BB.Investors are cautioned that a security rating is not a recommendation to buy, sell or hold securities, that it may be subject to revision or withdrawal at any time by the assigning rating organization, and that each rating should be evaluated independently of any other rating.

Long-term Obligations and Commitments The following table shows PNMs 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.

PAY M E N T S D U E (In thousands)

CONTRACTUAL OBLIGATIONS TOTAL LESS THAN 1 YEAR 2-3 YEARS 4-5 YEARS AFTER 5 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 35 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.

PNMs 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 Companys off-balance sheet obligations are limited to PNMs operating leases and certain financial instruments related to the purchase and sale of energy (see below). The present value of PNMs 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 into 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. PNMs 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.

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.

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.

Contingent Provisions of Certain Obligations The Company and PNM have a number of debt obligations and other contractual commitments that contain contingent pro-visions. Some of these, if triggered, could affect the liquidity of the Company. The 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 PNMs 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 36 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 PNMs mortgage. The amount of SUNs that may be issued is not limited by the SUNs indenture. However, debt-to-capital requirements in certain of PNMs 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 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 hedged interest rate on the refinancing to 4.9% plus an adjustment for the Companys and industrys credit rating. PNM assessment of hedge effectiveness is based on changes in the hedged 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 dur-ing 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 companys 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations Stock Repurchase In March 1999, PNMs 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, PNMs 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.

On August 8, 2000, PNMs 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 Companys Board of Directors reviews the Companys dividend policy on a continuing basis. The declaration of common dividends is dependent upon a number of factors including the ability of the Companys subsidiaries to pay dividends.

Currently, PNM is the Companys primary source of dividends. As part of the order approving the formation of the holding com-pany, 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 deter-mined 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 37 dividends, the availability of retained earnings, its financial circumstances and performance, the PRCs 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 Companys ability to pay dividends.

Consistent with the PRCs 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 Companys 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 Companys 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 Companys expectation of future operating cash flows and the cash needs of its planned increase in generating capacity.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations Capital Structure The Companys 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 PNMs 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 Mexicos Electric Utility Industry Restructuring Act of 1999 (the Restructuring Act) was enacted into law.

The Restructuring Act opens the states 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 circum-stances. The Restructuring Act, as amended, will give schools, residential and small business customers the opportunity to 38 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 of 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 gen-eration business activities until corporate separation is implemented.

On December 31, 2001, the Company implemented the holding company structure without corporate separation of supply service and energy-related services assets from distribution and transmission services assets. This structure provides for a holding company whose current holdings will be PNM, Avistar and other inactive unregulated subsidiaries. This was effected through the share exchange between PNM shareholders and the holding company, PNM Resources. Avistar and most of the inactive unregulated subsidiaries became wholly-owned subsidiaries of the holding company in January 2002. The transfer of certain corporate related assets to the holding company also occurred in January 2002. There are no current plans to provide the holding company with significant debt financing.

The 2002 session of the New Mexico Legislature resulted in enactment of tax measures favorable to the construction of merchant generating plants and plants fueled by renewable resources. The new laws provide authority for all local govern-ments 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 states 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 RTOs 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.

39 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 gener-ation 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 Companys previous proposal to recover its stranded costs under the original customer choice implementation dates would not accurately represent the Companys 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 Companys 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 regula-tory assets will be fully recovered in future rates, including through a non-bypassable wires charge.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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.

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 Acts 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 tran-sition 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 40 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 PNMs share of the PVNGS decommissioning costs excluding spent fuel disposal will be approximately $181.0 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 Companys growth plans.

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 Companys rebuttal testimony, culminating in a hearing scheduled for June 10, 2002.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations In November 2001, the Company began settlement negotiations with the PRCs 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 Companys earnings in 2001 was derived from the Companys 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. 41 These circumstances were aggravated by other factors such as increases in gas supply costs, weather conditions and trans-mission constraints. The FERC and the California Public Utilities Commission (CPUC) have entered a series of orders addressing, respectively, the wholesale pricing of electricity into the California market and the retail pricing of electricity to California consumers. These initiatives 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 Companys 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 Californias 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 softprice 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations California, and in most instances, were offset by the amounts due suppliers from the Cal PX and Cal ISO. California had demand-ed refunds of approximately $9 billion from power suppliers. On July 25, 2001, acting on the recommendation of the adminis-trative 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.

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 states 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 PXs 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-backmechanism.

42 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 Companys 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 addi-tional allowance against revenue of $3.5 million for anticipated losses to reflect managements 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 managements estimate of potential uncollectible accounts. The Company will continue to monitor the wholesale power marketplace and adjust its estimates accordingly.

The CPUC has commenced an investigation into the functioning of the California wholesale power market and its associated impact on retail rates. The Company, along with other power suppliers in California, has been served with a subpoena in connection with this investigation and has responded to the subpoena. The Company has been advised that the California Attorney General is conducting an investigation into possibly unlawful, unfair or anti-competitive behavior affecting electricity rates in California, and that Company documents will be subpoenaed in the future in connection with this investigation. 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 SCEs 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 partici-pant 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.

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 43 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 KCCs 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 agree-ment, 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 Companys 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 KCCs 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 KCCs rate order.

The Company is currently unable to predict the outcome of its litigation with Western Resources.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 managements 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))

Allowance for doubtful accounts, beginning (In thousands) 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) 44 Note: Above schedule excludes bad debt allowance for the Generation and Trading Operations EFFECTS OF CERTAIN EVENTS ON FUTURE REVENUES The Companys 100 MW power sale contract with San Diego Gas and Electric Company (SDG&E) expired on April 30, 2001 following FERCs 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 Companys 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 Companys 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 subject to requests for rehearing or judicial review. An order establishing terms and conditions (including com-pensation 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 Companys 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 FERCs 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 Companys 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Companys 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 EPAs nationwide effort of verifying that changes made at the countrys utilities have not inadvertently triggered a modification under the Clean Air Acts Prevention of Significant Determination (PSD) policies.The Company has responded to the NMED 45 information request.

The nature and cost of the impacts of EPAs 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition 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 GCTs intent to file a so-called citizen suit under the Clean Air Act (Clean Air), 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 GCTs 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 SJGSs 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 believes firmly that the allegations are without merit. By letter to GCTs 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 46 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 PRCs 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 Bureaus investigation. There can be no assurance that the outcome of this matter will not have a material impact on the results of operations and financial position of the Company.

NAVAJO NATION TAX ISSUES Arizona Public Service Company (APS), the operating agent for Four Corners, has informed the Company that in March 1999, APS initiated discussions with the Navajo Nation regarding various tax issues in conjunction with the expiration of a tax waiver, in July 2001, which was granted by the Navajo Nation in 1985. The tax waiver pertains to the possessory interest tax and the business activity tax associated with the Four Corners operations on the reservation. The Company believes that the resolu-tion 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 Companys 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 assets 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 Companys operating results and financial position at this time.

Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144). In August 2001, the FASB issued SFAS 144. The statement retains the requirements of the previously issued pronouncement on asset impairment, Statement of Financial Accounting Standards No. 121 (SFAS 121); however the SFAS 144 removes goodwill from the scope of SFAS 121, provides for a probability-weighted cash flow estimation approach for estimating possible future cash flows, and establishes a primary asset approach for a group of assets and liabilities that repre-sents 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 47 Statements made in this annual report 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 Companys 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 Companys results or outcomes to differ materially from those indicated by such forward-looking statements in this filing.

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 Companys 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 Companys financial instruments is set forth in Critical Accounting Policies section of Managements Discussion of Results of Operations and Financial Condition and the Financial Instruments note in the to the Notes to the Consolidated Financial Statements and incorporated by reference. The following additional information is provided.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations Risk Management The Company controls the scope of its various forms of risk through a comprehensive set of policies and procedures and over-sight by senior level management and the Board of Directors. The Companys 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 responsi-bility for establishing and enforcing the policies, procedures and limits and evaluating the risks inherent in proposed transactions, on an enterprise-wide basis.

The RMCs 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 48 on segregation of duties; policies on marking to market; responsibilities for trade capture; confirmation procedures; responsi-bilities 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 Companys wholesale power marketing operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Companys aggregate net open position is covered by its own excess generation capabilities. The Company is exposed to market risk if its generation capabilities were disrupted or if its jurisdictional load requirements were greater than anticipated. If the Company were required to cover all or a portion of its net open contract position, it would have to meet its commitments through market purchases.

The Company assesses the risk of these derivatives using the VAR method, in order to maintain the Companys 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 charac-teristics 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

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Companys positions, the Companys 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 Companys 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 Companys 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 Companys 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 Companys 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 Companys credit risk with its largest counterparty as of December 31, 2001 and 2000 was $7.5 million and $16.7 million respectively.

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 49 costs of the program, is recoverable through the Companys 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements discussion and analysis of financial condition and results of operations 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 Companys long-term debt is fixed-rate debt, and therefore, does not expose the Companys 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 Companys 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 Companys 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 Companys and Industrys credit rating. At December 31, 2001, the fair 50 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 Companys pension plan, and other postre-tirement 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.

Equity Market Risk As discussed above under Interest Rate Risk, the Company contributes to trusts established to fund its share of the decom-missioning 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.

PNM RESOURCES, INC. AND SUBSIDIARIES managements responsibility for financial statements and report of independent public accountants MANAGEMENTS RESPONSIBILITY FOR FINANCIAL STATEMENTS The accompanying financial statements, which consolidate the accounts of PNM Resources, Inc. and its subsidiaries, 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 the Companys 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.

The Audit Committee of the Board of Directors, 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.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors and Stockholders of PNM Resources, Inc.:

We have audited the accompanying consolidated balance sheets and statements of capitalization of PNM Resources, Inc.

(a New Mexico Corporation) and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of 51 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 Company's 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 man-agement, 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 as of December 31, 2001 and 2000, and the results of its operations and its 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

PNM RESOURCES, INC. AND SUBSIDIARIES pnm resources, inc. and subsidiaries consolidated statements of earnings YEAR ENDED DECEMBER 31, 2001 2000 1999 Operating Revenues: (In thousands, except per share amounts)

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 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 7,706) (20,382) (17,298) 52 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 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) $ 3.83) $ 2.54) $ 2.01)

Net Earnings per Share of Common Stock (Diluted) $ 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.

PNM RESOURCES, INC. AND SUBSIDIARIES pnm resources, inc. and subsidiaries consolidated balance sheets assets YEAR ENDED DECEMBER 31, 2001 2000 Utility Plant, at original cost except PVNGS: (In thousands)

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 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 53 of $18,025 and $13,279 147,787 238,426 Other receivables 52,158 64,857 Inventories 36,483 36,091 Regulatory assets 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 197,948 228,255 Prepaid pension cost 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.

PNM RESOURCES, INC. AND SUBSIDIARIES consolidated balance sheets capitalization and liabilities YEAR ENDED DECEMBER 31, 2001 2000 Capitalization: (In thousands)

Common stock equity:

Common stock outstanding - 39,118 shares, 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 without mandatory redemption requirements 12,800) 12,800)

Long-term debt, less current maturities 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:

54 Accumulated deferred income taxes 120,153) 166,249)

Accumulated deferred investment tax credits 44,714) 47,853)

Regulatory liabilities 52,890) 65,552)

Regulatory liabilities related to accumulated deferred income tax 14,163) 20,696)

Accrued post-retirement benefits cost 14,929) 11,899)

Other deferred credits 367,792) 311,569)

Total deferred credits 614,641) 623,818)

$ 2,934,638) $ 2,889,917)

The accompanying notes are an integral part of these financial statements.

PNM RESOURCES, INC. AND SUBSIDIARIES consolidated statements of cash flows YEAR ENDED DECEMBER 31, 2001) 2000) 1999)

Cash Flows From Operating Activities: (In thousands)

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 lessors 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) 55 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 35,000) -) 11,500)

Repayments -) (32,800) (58,200)

Exercise of employee stock options (2,179) (1,232) 1,453)

Common stock repurchase -) (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.

PNM RESOURCES, INC. AND SUBSIDIARIES consolidated statements of capitalization AS OF DECEMBER 31, 2001) 2000)

Common Stock Equity: (In thousands)

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:

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:

Issue and Final Maturity First Mortgage Bonds, Pollution Control Revenue Bonds:

5.700% 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:

56 6.300% due 2016 77,045) 77,045) 5.750% due 2022 37,300) 37,300) 5.800% due 2022 100,000) 100,000) 6.375% due 2022 90,000) 90,000) 6.375% due 2023 36,000) 36,000) 6.400% due 2023 100,000) 100,000) 6.300% due 2026 23,000) 23,000) 6.600% due 2029 11,500) 11,500)

Total Senior Unsecured Notes, Pollution Control Revenue Bonds 474,845) 474,845)

Senior Unsecured Notes:

7.100% due 2005 268,420) 268,420) 7.500% due 2018 100,025) 100,025)

Other, including unamortized premium and (discounted), net (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.

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. 57

PNM RESOURCES, INC. 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.

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 Companys 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 58 regulatory liabilities are enumerated and discussed in the Regulatory Assets and Liabilities note.

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. 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 Regulatory Assets and Liabilities note 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-Subtantive Lessors, Residual Value Guarantees and Other Provisions in Leasing Transactions. All significant intercompany transactions and balances have been eliminated.

Financial Statement Preparation and Presentation 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 of San Juan Generating Station (SJGS) Unit 4 and the Companys 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 PNMs preparation for the competitive electric energy market.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 PVNGS Units 1 and 2. Pursuant to a rate 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 Companys 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 Companys 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 Companys 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 Companys 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. 59 The Companys 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 settlingis 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 Companys trading contracts are recognized as adjustments to Generation and Trading Operations operating revenues. The market prices used to value these trading transactions reflect managements 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 Companys 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 Companys gas purchase costs are recoverable under a similar Purchased Gas Adjustment Clause administered by the PRC.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 60 amortized over the lives of the respective issues. Amounts associated with the Companys 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 Financial Instruments note).

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 Companys 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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.

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 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 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 61 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 Lease Commitments).

Change in Presentation Certain prior year amounts have been reclassified to conform to the 2001 financial statement presentation.

Segment Information As it currently operates, the Companys principal business segments are Utility Operations, which include Electric Services (Electric) and Gas Services (Gas), and Generation and Trading Operations (Generation and Trading). Electric consists of two major business lines that include distribution and transmission. The transmission business line does not meet the definition of a segment due to its immateriality and is combined with the distribution business line for disclosure purposes.

UTILITY OPERATIONS Electric 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 Companys 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 Gas The Companys 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 Companys customer base includes both sales-service customers and transportation-service customers.

In 2000 and the first quarter of 2001, the Companys Generation and Trading Operations procured its gas fuel supply from Gas. In the second quarter of 2001, the Companys 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 Companys Generation and Trading Operations serve four principal markets. These include sales to the Companys 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.

UNREGULATED AND OTHER The Companys 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 other immaterial corporate activities and eliminations.

62 RISKS AND UNCERTAINTIES The Companys 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 Companys 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 )

Twelve Months Ended: (In thousands) 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)

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements 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 )

Twelve Months Ended: (In thousands) 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 63 UNREGULATED ELECTRIC ) GAS ) TOTAL ) GENERATION ) AND OTHER ) CONSOLIDATED Twelve Months Ended: (In thousands) 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)

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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)

Assets: (In thousands)

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) 64 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)

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 Substantially all of the Companys 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.

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 under-lying generation assets.

Approximately $142 million of costs associated with the unregulated businesses under the Restructuring Act were established as regulatory assets. Because of the Companys belief that recovery through rates is probable as established by law, these assets continue to be classified as regulatory assets, although the Companys 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 Companys 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 65 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.

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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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)

Assets: (In thousands)

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.

66 Capitalization Changes in common stock and retained earnings are as follows:

COMMON STOCK NUMBER A G G R E G AT E R E TA I N E D OF SHARES PA R VA L U E EARNINGS (Dollars in thousands)

Balance at December 31, 1999 40,703,383) $656,910) $227,829)

Stock repurchases (1,585,584) (27,867) -)

Tax benefit from exercise of stock option -) (1,232) -)

Net earnings -) -) 100,946)

Dividends:

Cumulative preferred stock -) -) (586)

Common stock -) -) (31,346)

Balance at December 31, 2000 39,117,799) 627,811) 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) $625,632) $415,388)

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 Companys subsidiaries to pay dividends. Currently, PNM is the Companys 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 deter-mined 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 PRCs 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 Companys ability to pay dividends.

Consistent with the PRCs 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 Companys 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 Companys 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 67 the Companys expectation of future operating cash flows and the cash needs of its planned increase in generating capacity.

In March 1999, PNMs 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 repur-chase 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.

On August 8, 2000, PNMs Board of Directors approved a plan to repurchase up to $35 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 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.

Cumulative Preferred Stock No company preferred stock is outstanding. The Companys restated articles of incorporation authorizes 10 million shares of preferred stock, which may be issued without restriction. 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 PNMs 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 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 sen-ior debt of PNM.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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. The Company 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 Company has $25 million in local lines of credit.

There were $35.0 million in outstanding borrowings, 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. The Company was in compliance with all covenants under the Facility.

Lease Commitments 68 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 PNMs PVNGS Units 1 and 2 lease agreements limit PNMs 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.

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 Capitalization note), 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 PNMs future min-imum operating lease payments below, reflects the net cash outflow related to the PVNGS leases.

PNMs 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 Financial Instruments The estimated fair value of the Companys 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 $150,781 $ - $ -

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 Fair value is based on market quotes provided by the Companys 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 Companys various trusts. The Company also uses certain derivative instruments for bulk power electricity trading purposes in order to take advantage of 69 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 Companys credit risk with its largest counterparty as of December 31, 2001 and 2000 was $7.5 million and

$16.7 million respectively.

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 Companys 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 Companys 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 compo-nent 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 Companys 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 Companys 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

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 and recorded as a component of Other Comprehensive Income. These gains and losses were reclassified and recognized in earnings as an adjustment to the Companys 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 Companys 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 Companys 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.

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 Companys Generation and Trading Operations enter into forward physical contracts for the sale of the Companys 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.

70 The Companys Generation and Trading Operations, including both firm commitments and trading activities, are managed through an asset backed strategy, whereby the Companys 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 PNMs and the industrys credit rating. PNMs assessment of hedge effectiveness is based on changes in the interest rates and PNMs 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.

A forward starting swap does not require any upfront premium and captures changes in the corporate credit component of an investment grade companys interest rate as well as the underlying Treasury benchmark. The five forward 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.

Hedge of Trust Assets In February 2001, PNM terminated certain financial derivatives based on the Standard & Poors (S&P) 500 Index. These 71 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 PNMs result of operations.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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)

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 - - 0.08 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 72 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 - - 0.08 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 Companys 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:

73 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%

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements 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:

74 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.

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. The Companys 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 Companys 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 con-sist 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 The following sets forth the pension plans 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) 75 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%

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)

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 plans 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) 76 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%

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 postretirement 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 Companys projected benefit obligation and accumulated benefit obligation for this program, as of December 31, 2001 and 2000, was $17.7 million and $16.9 million, respectively. As of the plan valuation date of September 30, 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

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 may, but is not obligated to, provide funds to the trust, which was established with an independent trustee, to aid it in meet-ing 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.

Stock Option Plans The Companys 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 Companys 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.

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 Companys Director Retainer Plan 77 (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 Companys 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 out-standing as of December 31, 2001, was 33,000. Restricted Stock issuances were based on the fair market value of the Companys 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.

A summary of the status of the Companys 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 AV E R A G E AV E R A G E AV E R A G E 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 Options available for future grant 2,500,000 - 2,183,624

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 The following table summarizes information about stock options outstanding at December 31, 2001:

O P T I O N S O U T S TA N D I N G OPTIONS EXERCISABLE WEIGHTED AV E R A G E WEIGHTED WEIGHTED RANGE OF NUMBER REMAINING AV E R A G E NUMBER AV E R A G E EXERCISE O U T S TA N D I N G CONTRACTUAL EXERCISE EXERCISABLE EXERCISE FIXED OPTIONS AT 1 2 / 3 1 / 0 1 LIFE PRICES AT 1 2 / 3 1 / 0 1 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 Had compensation expense for the Companys 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 Companys 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 78 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 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%

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 Construction Program and Jointly-Owned Plants The Companys construction expenditures for 2001 were approximately $264.9 million, including expenditures on jointly-owned projects. The Companys proportionate share of expenses for the jointly-owned plants is included in operating expenses in the consolidated statements of earnings.

At December 31, 2001, the Companys interests and investments in jointly-owned generating facilities are:

CONSTRUCTION PLANT IN A C C U M U L AT E D WORK IN COMPOSITE S TAT I O N ( F U E L T Y P E ) SERVICE D E P R E C I AT I O N 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 Companys interest in PVNGS Unit 3, the Companys interest in common facilities for all PVNGS units and the Companys 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 79 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)

PNM 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. PNM has a 10.2% undi-vided interest in PVNGS, with portions of its interests in Units 1 and 2 held under leases (see Commitments and Contingencies note for additional discussion).

Commitments and Contingencies Long-Term Power Contracts PNM has a power purchase contract with Southwestern Public Service Company (SPS), which originally provided for the pur-chase 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 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 PPAs maximum dependable capacity is 132 MW. In July 2000, the plant went into opera-tion. 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 In July 2001, PNM entered into a long-term wholesale power contract with Texas-New Mexico Power (TNMP) to provide power to serve TNMPs 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 TNMPs sole supplier beginning January 1, 2003. In the last year of the contract, it is estimated that TNMP will need 114 MW 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.

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.

80 The natural gas used as fuel by Generation and Trading was delivered by Gas. In the second quarter of 2001, the Companys 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 the Company 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 opera-tional by July 2002. The planned plants are part of PNMs 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 Companys 10.2% interest in the three PVNGS units, the Companys maximum potential assessment per incident for all three units is approximately $27.0 million, with an annual payment limitation of $3 million per incident. If the funds provided by this retrospective assessment program prove to be insufficient, Congress could impose revenue raising measures on the nuclear industry to pay claims.

Aspects of the Federal law referred to above (the Price-Anderson Act), which provides for payment of public liability claims in case of a catastrophic accident involving a nuclear power plant are up for renewal in August 2002. While existing nuclear power plant would continue to be covered in any event, the renewal would extend coverage to future nuclear power plants and could contain amendments that would affect existing plants. A renewal bill was passed by the House with unanimous consent on November 27, 2001. The House proposed a change in the annual retrospective premium limit from $10 million to

$15 million per reactor per incident. Additionally, the House proposed to amend the maximum potential assessment from $88.1 million to $98.7 million per reactor per incident, taking into account effects of inflation. On March 7, 2002 the Senate approved

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 NRCs recommendation. However, if adopted, certain changes in the law could possibly trigger Deemed Loss Eventsunder the Companys 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 investors interest in PVNGS, cash in the amount as provided in the lease and (ii) assume debt obligations relating to the PVNGS lease (see Lease Commitment note).

The PVNGS participants maintain all-risk(including nuclear hazards) insurance for nuclear property damage to, and decon-tamination 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-riskand 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 Companys 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 Companys share of the PVNGS decommissioning costs excluding spent 81 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.

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 accom-modate 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 oper-ation 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 Companys 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 PRCs Pipeline Safety Bureau which issued its report on March 18, 2002. The Bureaus report gave 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 Bureaus

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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.

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 KCCs 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 82 the KCC orders, failed to assist in efforts to reverse the KCC orders, refused to renegotiate within the terms of the agreement, inter-fered with Western Resourcess 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 Companys 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 KCCs split-off orders. The Court ruled that, by filing a new financial plan in compliance with the orders, Western Resources had 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 KCCs 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.

PNM RESOURCES, INC. AND SUBSIDIARIES notes to consolidated financial statements december 31, 2001, 2000 and 1999 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 Companys recorded estimated minimum liability to remediate its identified sites is $6.8 million. The ultimate cost to clean up the Companys identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; and the time periods over which site remediation is expected to occur. The Company believes that, due to these uncertainties, it is remotely possible that cleanup costs could exceed its recorded liability by up to $11.6 million. The upper limit of this range of costs was estimated using assumptions least favorable to the Company.

For the 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 83 material impact on the results of operations or financial condition of the Company.

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 assets 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 Companys 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 assetapproach 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.

PNM RESOURCES, INC. AND SUBSIDIARIES 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 84 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.

PNM RESOURCES, INC. AND SUBSIDIARIES 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 ThroughputDecatherms (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 85 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 (Continued on page 86)

PNM RESOURCES, INC. AND SUBSIDIARIES comparative operating statistics (unaudited)

(Continued from page 85) 2001 2000 1999 1998 1997 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 86

PNM RESOURCES, INC. AND SUBSIDIARIES comparative operating statistics (unaudited) 2001) 2000 1999 1998 1997 Generation and Trading Operations Sales:

Energy SalesKWh (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 CapabilityKW 1,521,000) 1,521,000 1,521,000 1,506,000 1,506,000 87 Coincidental Peak DemandKW 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

PNM RESOURCES shareholders information Annual Stockholders Meeting The 2002 Annual Meeting of Stockholders will be held at 9:30 AM on May 14, 2002 at: The South Broadway Cultural Center, 1025 Broadway SE, Albuquerque, NM. Proxies will be requested from stockholders when the notice of meeting and proxy statement are mailed on or about April 10.

Stock Listing The Common Stock is listed on the New York Stock Exchange. The Common Stock ticker symbol is PNM. The press listing is PNM Res. As of December 31, 2001, there were 15,377 common shareholders of record.

Transfer Agent and Registrar PNM Resources Shareholder Records Department, Alvarado Square, Mail Stop 1104, Albuquerque, NM 87158, Telephone (toll-free): 800-545-4425, Fax: 505-241-4311, E-Mail: yjohnso@pnm.com Dividend Reinvestment and Direct Stock Purchase Plan PNM Resources offers a dividend reinvestment and direct stock purchase plan as a service to all interested participants.

In addition to full or partial reinvestment of dividends, the PNM Direct Plan gives shareholders the opportunity to make direct cash investments ranging from $50 to $5,000 as often as once a month. Information regarding the Plan can be obtained by calling Shareholder Records at 800-545-4425.

Additional Information 88 The Company reports details concerning its operations and other matters annually to the Securities and Exchange Commission on Form 10-K, which is available without charge to the Companys security holders, upon written request to the Senior Vice President of Communications, Investor Services and Community Relations.

A supplement containing additional financial and operating data for the latest 10-year period may be obtained by writing to the Senior Vice President of Communications, Investor Services and Community Relations.

For up-to-date stock quotes, quarterly earnings results and other important information, visit the PNM web site at pnm.com.

Contact Information CORPORATE HEADQUARTERS: PNM Resources, Inc., Alvarado Square, Albuquerque, NM 87158, 505-241-2700 INVESTOR RELATIONS: Barbara L. Barsky, Senior Vice President, Communications, Investor Services and Community Relations, Telephone: 505-241-2662; Fax: 505-241-2368; E-Mail: bbarsky@pnm.com NEW MEXICO UTILITY SHAREHOLDERS ALLIANCE: P.O. Box 728, Albuquerque, NM 87103 COMMON STOCK PRICES AND DIVIDENDS PAID: (in dollars) 2001 2000 QUARTER DIVIDEND HIGH LOW DIVIDEND HIGH LOW 1 $0.20 $29.340 $22.875 $0.20 $16.875 $14.625 2 $0.20 $37.800 $28.700 $0.20 $18.000 $15.313 3 $0.20 $33.550 $24.720 $0.20 $26.440 $15.375 4 $0.20 $28.680 $24.350 $0.20 $28.313 $20.750

board of directors of PNM Resources officers of PNM Resources ROBERT G. ARMSTRONG *JEFFRY E. STERBA, 46 President of Armstrong Chairman, President and Energy Corporation, Age 55, Chief Executive Officer Director since 1991

• ROGER J. FLYNN, 59 R. MARTIN CHAVEZ, PH.D.

Executive VP, Electric and Chairman and Chief Gas Services Executive Officer of *WILLIAM J. REAL, 53 Kiodex, Inc., Age 38, Executive VP, Power Production Director since 2001 and Marketing JOYCE A. GODWIN *BARBARA L. BARSKY, 57 Retired President and Senior VP, Communications, Investor Secretary of Presbyterian Services, and Community Relations Healthcare Services, Age 58, Director since 1989 *ALICE A. COBB, 44 Senior VP, People Services BENJAMIN F. MONTOYA and Development Retired Chairman, President *MAX H. MAERKI, 62 and Chief Executive Officer Senior VP and Chief Financial Officer of PNM, Age 66, Director since 1993 PATRICK T. ORTIZ, 52 Senior VP, General Counsel and Secretary MANUEL T. PACHECO, PH.D.

President, University of *EDDIE PADILLA, JR., 48 Missouri System, Age 60, Senior VP, Bulk Power Marketing Director since 2001 and Development

• R. BLAKE RIDGEWAY, 43 THEODORE F. PATLOVICH Senior VP, Energy Services Retired Vice Chairman and Senior VP Of Loctite ERNEST T. CDE BACA, 48 Corporation, Age 75, VP, Governmental Affairs Director since 2000 TERRY R. HORN, 49 ROBERT M. PRICE VP and Treasurer President of PSV, Inc. a JOHN R. LOYACK, 38 technology consulting VP, Corporate Controller and Chief business, Age 71, Accounting Officer Director since 1992

• Board of Directors of PNM PAUL F. ROTH Retired President of the officers of PNM Texas Division of Southwestern Bell Michael Barley Studio Telephone Company, Age 69, MELVIN J. CHRISTOPHER, 41 Director since 1991 VP, Operations and Engineering JEFFRY E. STERBA PATRICK J. GOODMAN, 52 Chairman, President and VP, Generation Construction Chief Executive Officer of and Operations photography:

PNM Resources, Inc., Age 46, Director since 2000 SARITA P. LOEHR, 45 VP, Customer Service Audit Committee and Ethics Committee CINDY E. MCGILL, 45 Kilmer & Kilmer VP, Regulatory Policy and Public Policy Customer Policy Committee Finance Committee JOHN H. MYERS, 44 Board Governance and Human VP, Construction and Reliability Resources Committee design:

Effective as of 3/25/02

W E H A V E T H E P O W E R P N M Alvarado Square

• Albuquerque, New Mexico 87158

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